As filed with the Securities and Exchange Commission on July 1, 2011

Registration No. 333-174225

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Amendment No. 1
to

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933


Enduro Royalty Trust		Enduro Resource Partners LLC
(Exact Name of co-registrant as specified in its charter)		(Exact Name of co-registrant as specified in its charter)
Delaware		Delaware
(State or other jurisdiction of incorporation or organization)		(State or other jurisdiction of incorporation or organization)
1311		1311
(Primary Standard Industrial Classification Code Number)		(Primary Standard Industrial Classification Code Number)
45-6259461		27-2036288
(I.R.S. Employer Identification No.)		(I.R.S. Employer Identification No.)
919 Congress Avenue, Suite 500 Austin, Texas 78701 (512) 236-6599		777 Main Street, Suite 800 Fort Worth, Texas 76102 (817) 744-8200 Attention: John W. Arms
(Address, including zip code, and telephone number, including area code, of co-registrant’s Principal Executive Offices)		(Address, including zip code, and telephone number, including area code, of co-registrant’s Principal Executive Offices)


The Bank of New York Mellon Trust Company, N.A., Trustee 919 Congress Avenue, Suite 500 Austin, Texas 78701 (512) 236-6599 Attention: Michael J. Ulrich (Name, address, including zip code, and telephone number, including area code, of agent for service)		Jon S. Brumley 777 Main Street, Suite 800 Fort Worth, Texas 76102 (817) 744-8200 (Name, address, including zip code, and telephone number, including area code, of agent for service)

Copies to:


Sean T. Wheeler Latham & Watkins LLP 717 Texas Avenue, Suite 1600 Houston, Texas 77002 (713) 546-5400		Joshua Davidson Gerald M. Spedale Baker Botts L.L.P. 910 Louisiana, Suite 3200 Houston, Texas 77002 (713) 229-1234

Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective.

If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. o

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer o	Accelerated filer o	Non-accelerated filer þ	Smaller reporting company o

(Do not check if a smaller reporting company)

The co-registrants hereby amend this Registration Statement on such date or dates as may be necessary to delay its effective date until the co-registrants shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

The information in this prospectus is not complete and may be changed. These securities may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

Subject to Completion dated July 1, 2011

PROSPECTUS

[ ] Trust Units

This is the initial public offering of units of beneficial interest in Enduro Royalty Trust, or the “trust.” Enduro Sponsor (as defined in the “Prospectus Summary”) has formed the trust and, immediately prior to the closing of this offering, will convey, or cause to be conveyed, a net profits interest in oil and natural gas properties (the “Net Profits Interest”) to the trust in exchange for [ ] trust units. Enduro Sponsor is offering [ ] trust units to be sold in this offering and will receive all of the proceeds derived therefrom. After the offering, Enduro Sponsor will own [ ] trust units, or [ ] trust units if the underwriters exercise their option to purchase additional trust units from Enduro Sponsor. No public market currently exists for the trust units. Enduro Sponsor is a privately-held limited liability company engaged in the production and development of oil and natural gas from properties located in Texas, Louisiana and New Mexico.

The trust intends to apply to have the trust units approved for listing on the New York Stock Exchange under the symbol “NDRO.”

Enduro Sponsor expects that the public offering price will be between $ and $ per trust unit.

The trust units. Trust units are equity securities of the trust and represent undivided beneficial interests in the trust assets. They do not represent any interest in Enduro Sponsor.

The trust. The trust will own the Net Profits Interest, which represents the right to receive 80% of the net profits from the sale of production from oil and natural gas properties in Texas, Louisiana and New Mexico, which are referred to as the “Underlying Properties,” held by Enduro Sponsor as of the date of the conveyance of the Net Profits Interest to the trust. Enduro Sponsor will retain the remaining 20% of the net profits from the sale of production from the Underlying Properties as of the date of the conveyance.

The trust unitholders. As a trust unitholder, you will receive monthly distributions of cash from the proceeds that the trust receives from Enduro Sponsor pursuant to the Net Profits Interest. The trust’s ability to pay monthly cash distributions will depend on its receipt of net profits attributable to the Net Profits Interest, which will depend upon, among other things, volumes produced, wellhead prices, price differentials, production and development costs, potential reductions or suspensions of production and the amount and timing of trust administrative expenses.

Investing in the trust units involves a high degree of risk. Please read “Risk Factors” beginning on page 17 of this prospectus.


	Per Trust Unit	Total

Price to the public	$	$
Underwriting discounts and commissions⁽¹⁾	$	$
Proceeds, before expenses, to Enduro Sponsor	$	$


⁽¹⁾		Excludes a structuring fee of [ ]% of the gross proceeds of the offering payable to Barclays Capital Inc. by Enduro Sponsor for the evaluation, analysis and structuring of the trust.

Enduro Sponsor has granted the underwriters a 30-day option to purchase up to an additional [ ] trust units from it on the same terms and conditions set forth above if the underwriters sell more than [ ] trust units in this offering.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

Barclays Capital, on behalf of the underwriters, expects to deliver the trust units on or about , 2011.


Barclays Capital	Citi	Goldman, Sachs & Co.	RBC Capital Markets	Wells Fargo Securities

Prospectus dated , 2011

TABLE OF CONTENTS


PROSPECTUS SUMMARY		1
RISK FACTORS		17
FORWARD-LOOKING STATEMENTS		34
USE OF PROCEEDS		35
ENDURO SPONSOR		36
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS		42
THE TRUST		43
PROJECTED CASH DISTRIBUTIONS		44
THE UNDERLYING PROPERTIES		51
COMPUTATION OF NET PROFITS		77
DESCRIPTION OF THE TRUST AGREEMENT		81
DESCRIPTION OF THE TRUST UNITS		86
TRUST UNITS ELIGIBLE FOR FUTURE SALE		89
FEDERAL INCOME TAX CONSEQUENCES		91
STATE TAX CONSIDERATIONS		98
ERISA CONSIDERATIONS		99
SELLING TRUST UNITHOLDER		100
UNDERWRITING (CONFLICTS OF INTEREST)		101
LEGAL MATTERS		106
EXPERTS		106
WHERE YOU CAN FIND MORE INFORMATION		106
GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS		107
INDEX TO FINANCIAL STATEMENTS		F-1
INFORMATION ABOUT ENDURO RESOURCE PARTNERS LLC (ENDURO SPONSOR)		ENDURO-1
INDEX TO FINANCIAL STATEMENTS OF ENDURO SPONSOR		ENDURO F-1
SUMMARY OF RESERVE REPORT OF PREDECESSOR PROPERTIES		ANNEX A-1-1
SUMMARY OF RESERVE REPORT OF SAMSON PERMIAN BASIN ASSETS		ANNEX A-2-1
SUMMARY OF RESERVE REPORT OF CONOCOPHILLIPS PERMIAN BASIN ASSETS		ANNEX A-3-1
SUMMARY OF RESERVE REPORT OF THE UNDERLYING PROPERTIES		ANNEX B-1
SUMMARY OF RESERVE REPORT OF ENDURO ROYALTY TRUST		ANNEX C-1
EX-23.1
EX-23.2
EX-23.5

Important Notice About Information in This Prospectus

Enduro Sponsor and the trust have not, and the underwriters have not, authorized anyone to provide you with additional or different information. If anyone provides you with additional, different or inconsistent information, you should not rely on it. This prospectus is not an offer to sell or a solicitation of an offer to buy the trust units in any jurisdiction where such offer and sale would be unlawful. You should not assume that the information contained in this prospectus is accurate as of any date other than the date on the front of this document. The trust’s business, financial condition, results of operations and prospects may have changed since such date.

PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus. To understand this offering fully, you should read the entire prospectus carefully, including the risk factors and the financial statements and notes to those statements. Unless otherwise indicated, all information in this prospectus assumes (a) an initial public offering price of $ per trust unit and (b) no exercise of the underwriters’ option to purchase additional trust units.

Unless the context otherwise requires, as used in this prospectus, (i) “Predecessor Properties” refers to the East Texas and North Louisiana oil and natural gas properties acquired by Enduro Resource Partners LLC from Denbury Resources Inc. in December 2010, (ii) “Predecessor” refers to Enduro Resource Partners LLC after giving effect to the acquisition of the Predecessor Properties but without giving effect to the acquisition of the Acquired Properties, (iii) the “Acquired Properties” refers to the Permian Basin oil and natural gas properties acquired by the Predecessor from Samson Investment Company in January 2011 and from ConocoPhillips Company in February 2011, (iv) when discussing the assets, operations or financial condition and results of operations of Enduro Sponsor, unless otherwise indicated, “Enduro Sponsor” refers to the Predecessor after giving effect to the acquisition of the Acquired Properties, and when discussing oil and natural gas reserve information of Enduro Sponsor, refers to the estimated proved oil and natural gas reserves for the Predecessor after giving effect to the acquisition of the Acquired Properties as reflected in the reserve reports (as defined below) and (v) “Underlying Properties” refers to the portion of the Predecessor Properties in which the trust has a Net Profits Interest (as defined below) and the Acquired Properties after deducting all royalties and other burdens on production thereon as of the date of the conveyance of the Net Profits Interest to the trust. For more information on the Underlying Properties and the acquisition of the Acquired Properties by the Predecessor, please see “The Underlying Properties” and “Information about Enduro Resource Partners LLC (Enduro Sponsor),” respectively.

Cawley, Gillespie & Associates, Inc., referred to in this prospectus as “Cawley Gillespie,” an independent engineering firm, provided the estimates of proved oil and natural gas reserves as of December 31, 2010 included in this prospectus. These estimates are contained in summaries prepared by Cawley Gillespie of its reserve reports as of December 31, 2010 for the Predecessor Properties, Samson Permian Basin properties, ConocoPhillips Permian Basin properties, the Underlying Properties and the Net Profits Interest. These summaries are located at the back of this prospectus in Annexes A-1, A-2, A-3, B and C and are collectively referred to in this prospectus as the “reserve reports.” You will find definitions for terms relating to the oil and natural gas business in “Glossary of Certain Oil and Natural Gas Terms.”

Enduro Royalty Trust

Enduro Royalty Trust is a Delaware statutory trust formed in May 2011 by Enduro Sponsor to own a net profits interest representing the right to receive 80% of the net profits from the sale of oil and natural gas production from certain properties in the states of Texas, Louisiana and New Mexico held by Enduro Sponsor as of the date of the conveyance of the net profits interest to the trust. The conveyed interest is referred to as the “Net Profits Interest.” The trust will make monthly cash distributions of all of its monthly cash receipts, after deduction of fees and expenses for the administration of the trust, to holders of its trust units as of the applicable record date (generally the 15th day of each calendar month) on or before the 10th business day after the record date. The Net Profits Interest will be entitled to a share of the profits from production occurring on or after May 1, 2011. The trust is not subject to any pre-set termination provisions based on a maximum volume of oil or natural gas to be produced or the passage of time.

The Underlying Properties were acquired in three separate transactions and are located in two different geographic regions: the Permian Basin and East Texas/North Louisiana. As of December 31, 2010, approximately 99.3% of the wells on the Underlying Properties were operated by third party oil and natural gas companies with significant experience in the development and operation of oil and

natural gas properties (the “Third Party Operators”). The following table summarizes certain information regarding the proved reserves and production associated with the Underlying Properties as of and for the period indicated. The reserve reports were prepared by Cawley Gillespie in accordance with criteria established by the Securities and Exchange Commission (the “SEC”). For information regarding proved reserves and production related to the Net Profits Interest, please see “The Underlying Properties.”


	Underlying Properties
											Average Daily Net
	As of December 31, 2010										Production For Year
	Proved Reserves⁽¹⁾										Ended December 31,		As of December 31,
	PV-10		Total					% Proved Developed			2010		2010
Operating Area	Value⁽²⁾		(MBoe)⁽³⁾		% Oil			Reserves			(Boe per day)		R/P Ratio⁽⁴⁾
	(In thousands)

Permian Basin	$	279,975		16,321		78	%		96	%		3,526		13
East Texas/North Louisiana		69,557		10,743		0	%		48	%		2,321		13

Total	$	349,532		27,064		47	%		76	%		5,847		13


⁽¹⁾		In accordance with the rules and regulations promulgated by the SEC, the proved reserves presented above were determined using the twelve month unweighted arithmetic average of the first-day-of-the-month price for the period from January 1, 2010 through December 31, 2010, without giving effect to any hedge transactions, and were held constant for the life of the properties. This yielded a price for oil of $79.43 per Bbl and a price for natural gas of $4.37 per MMBtu.


⁽²⁾		PV-10 is the present value of estimated future net revenue to be generated from the production of proved reserves, discounted using an annual discount rate of 10%, calculated without deducting future income taxes. Standardized measure of discounted future net cash flows is calculated the same as PV-10 except that it deducts future income taxes and future abandonment costs. Because Enduro Sponsor bears no federal income tax expense and taxable income is passed through to the unitholders of the trust, no provision for federal or state income taxes is included in the reserve reports. PV-10 may not be considered a generally accepted accounting principle (“GAAP”) financial measure as defined by the SEC and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. The pre-tax PV-10 value and the standardized measure of discounted future net cash flows do not purport to present the fair value of the oil and natural gas reserves attributable to the Underlying Properties.


⁽³⁾		Oil equivalents in the table are the sum of the Bbls of oil and the Boe of the stated Mcfs of natural gas, calculated on the basis that six Mcfs of natural gas are the energy equivalent of one Bbl of oil.


⁽⁴⁾		The R/P ratio, or the reserves-to-production ratio, is a measure of the number of years that a specified reserve base could support a fixed amount of production. This ratio is calculated by dividing total estimated proved reserves of the subject properties at the end of a period by annual total production for the prior 12 months. Because production rates naturally decline over time, the R/P ratio is not a useful estimate of how long properties should economically produce. Based on the reserve reports, economic production from the Underlying Properties is expected for at least 50 more years.

The following graph shows estimated annual production of total proved reserves attributable to the Underlying Properties based upon the pricing and other assumptions set forth in the reserve reports. This graph presents the total proved volumes as reflected in the reserve reports broken down by two reserve categories (proved developed and proved undeveloped reserves) as of December 31, 2010.

The following table sets forth the five largest fields in the Underlying Properties, the operator(s) of each field and the PV-10 value represented by each field:


				% of Total
		PV-10 at		PV-10 at
Field Name	Operator	December 31, 2010		December 31, 2010
		(In thousands)

Elm Grove Field	Petrohawk Energy Corporation, J-W Operating, Questar Corporation	$	54,591		16	%
North Monument Grayburg Unit	Apache Corporation		42,989		12	%
North Central Levelland Unit	Apache Corporation		39,208		11	%
North Cowden Unit	Occidental Permian Ltd.		32,563		9	%
Yates Field Unit	Kinder Morgan Inc.		18,052		5	%

Total		$	187,403		53	%

Key Investment Considerations

The following are some key investment considerations related to the Underlying Properties, the Net Profits Interest and the trust units:


	•	Stable oil base combined with significant production and inventories of low risk natural gas locations. The Underlying Properties in the Permian Basin region include multiple mature oil fields currently using secondary and tertiary recovery methods. These fields typically are characterized by stable production profiles. Many of the Underlying Properties in the Permian Basin currently under waterflood have CO₂ recovery potential, which could increase the ultimate oil recovered from these fields. The Underlying Properties located in

the East Texas/North Louisiana region have significant natural gas production and near-term growth potential stemming primarily from the development of the Haynesville Shale and the horizontal Cotton Valley plays. Future increases in natural gas prices could accelerate development activity in this region, thereby increasing cash flows.


	•	Substantial proved developed reserves. Proved developed reserves are the most valuable and lowest risk category of reserves because their production requires no significant future development expenses. As of December 31, 2010, approximately 75% of the volumes and 91% of the PV-10 value of the proved reserves associated with the Underlying Properties were attributed to proved developed reserves.


	•	Additional development opportunities. Enduro Sponsor believes that the Underlying Properties are likely to offer economic development opportunities in the future that are not reflected in existing proved reserves and that could significantly increase future reserves and production. In the Permian Basin region, future increases in estimated oil recovery factors may increase reserves and production. Such increases in recovery factors may occur through, among other means, the implementation of additional enhanced recovery techniques, infill drilling and production outperformance. Examples of potential development opportunities not included in proved reserves in the East Texas/North Louisiana region include increased density drilling, refracs and development of prospective formations such as the Bossier Shale and Smackover, among others.


	•	Location in areas with significant histories of oil and natural gas production. Long producing histories in the Permian Basin and East Texas/North Louisiana regions provide for well established production profiles and increased certainty of production estimates. These regions also have significant access to oilfield services and pipeline takeaway infrastructure. In addition, Enduro Sponsor believes that operating risk is generally lower in regions accustomed to oil and natural gas production.


	•	Leading third party operators. In the Permian Basin region, approximately 70% of the PV-10 value of the proved reserves is operated by Occidental Petroleum, Apache Corporation or Kinder Morgan, all of whom are among the top 10 producers in the basin by volume. These operators also have many years of experience in maximizing production response from mature oil and natural gas fields through enhanced recovery techniques. In the East Texas/North Louisiana region, approximately 85% of the PV-10 value of proved reserves is operated by Petrohawk Energy Corporation and EXCO Resources, Inc. These companies are two of the most active operators in the Haynesville Shale play and have significant operating experience in the region.


	•	Downside commodity price protection. To mitigate the negative effects of a possible decline in oil and natural gas prices on distributable income to the trust, Enduro Sponsor has entered into hedge contracts with respect to approximately 70%, 76% and 67% of expected oil and natural gas production for 2011, 2012 and 2013, respectively, from the proved developed reserves attributable to the Underlying Properties in the reserve reports. These hedge contracts include a combination of fixed price swaps, collars and floors to protect the trust’s downside, while still allowing the trust to participate in increasing oil and natural gas markets. After December 31, 2013, none of the production attributable to the Underlying Properties will be hedged.


	•	High Operating Margins. The Underlying Properties have historically generated substantial operating margins. Lease operating expenses and property and other taxes on the Underlying Properties averaged $15.93 per Boe during the past three years. During the same period, the sales price for oil and natural gas averaged $52.65 per Boe, providing an operating margin of $36.72 per Boe, or 70%.


	•	Aligned interests of sponsor. Immediately following the closing of this offering, Enduro Sponsor will have an effective ownership of approximately [ ]% of the net profits attributable to the sale of oil and natural gas produced from the Underlying Properties, including its retained 20% interest in the net profits from the sale of production from the Underlying Properties and its ownership of approximately [ ]% of the trust units.

Formation Transactions

At or prior to the closing of this offering, the following transactions, which are referred to herein as the “formation transactions,” will occur:


	•	Enduro Sponsor will convey to the trust the Net Profits Interest effective as of May 1, 2011 in exchange for [ ] trust units in the aggregate, representing all of the outstanding trust units of the trust.


	•	Enduro Sponsor will sell [ ] trust units offered hereby, representing an [ ]% interest in the trust. Enduro Sponsor will also make available during the 30-day option period up to [ ] trust units for the underwriters to purchase at the initial offering price to cover over-allotments. Enduro Sponsor intends to use the proceeds of the offering as disclosed under “Use of Proceeds.”

Structure of the Trust

The following chart shows the relationship of Enduro Sponsor, the trust and the public trust unitholders after the closing of this offering.

Risk Factors

An investment in the trust units involves risks associated with fluctuations in energy commodity prices, the operation of the Underlying Properties, certain regulatory and legal matters, the structure of the trust and the tax characteristics of the trust units. Please read carefully the risks described under “Risk Factors” on page 17 of this prospectus.


	•	Prices of oil and natural gas fluctuate, and lower prices could reduce proceeds to the trust and cash distributions to trust unitholders.


	•	Estimates of future cash distributions to trust unitholders are based on assumptions that are inherently subjective.


	•	Actual reserves and future production may be less than current estimates, which could reduce cash distributions by the trust and the value of the trust units.


	•	The Third Party Operators are the operators of approximately 99.3% of the wells on the Underlying Properties and, therefore, Enduro Sponsor is not in a position to control the timing of development efforts, the associated costs or the rate of production of the reserves on such properties.


	•	Developing oil and natural gas wells and producing oil and natural gas are costly and high-risk activities with many uncertainties that could adversely affect future production from the Underlying Properties. Any delays, reductions or cancellations in development and producing activities could decrease revenues that are available for distribution to trust unitholders.


	•	The trust is passive in nature and neither the trust nor the trust unitholders will have any ability to influence Enduro Sponsor or control the operations or development of the Underlying Properties.

	•	Shortages of equipment, services and qualified personnel could increase costs of developing and operating the Underlying Properties and result in a reduction in the amount of cash available for distribution to the trust unitholders.

	•	The trust units may lose value as a result of title deficiencies with respect to the Underlying Properties.

	•	Enduro Sponsor may transfer all or a portion of the Underlying Properties at any time without trust unitholder consent, subject to specified limitations.


	•	The reserves attributable to the Underlying Properties are depleting assets and production from those reserves will diminish over time. Furthermore, the trust is precluded from acquiring other oil and natural gas properties or net profits interests to replace the depleting assets and production. Therefore, proceeds to the trust and cash distributions to trust unitholders will decrease over time.


	•	An increase in the differential between the price realized by Enduro Sponsor for oil or natural gas produced from the Underlying Properties and the NYMEX or other benchmark price of oil or natural gas could reduce the profits to the trust and, therefore, the cash distributions by the trust and the value of trust units.


	•	The amount of cash available for distribution by the trust will be reduced by the amount of any costs and expenses related to the Underlying Properties and other costs and expenses incurred by the trust.


	•	The generation of profits for distribution by the trust depends in part on access to and operation of gathering, transportation and processing facilities. Any limitation in the availability of those facilities could interfere with sales of oil and natural gas production from the Underlying Properties.


	•	The trustee must, under certain circumstances, sell the Net Profits Interest and dissolve the trust prior to the expected termination of the trust. As a result, trust unitholders may not recover their investment.

	•	Enduro Sponsor may sell trust units in the public or private markets, and such sales could have an adverse impact on the trading price of the trust units.

	•	There has been no public market for the trust units.

	•	The trading price for the trust units may not reflect the value of the Net Profits Interest held by the trust.


	•	Conflicts of interest could arise between Enduro Sponsor and its affiliates, on the one hand, and the trust and the trust unitholders, on the other hand.


	•	The trust is managed by a trustee who cannot be replaced except by a majority vote of the trust unitholders at a special meeting, which may make it difficult for trust unitholders to remove or replace the trustee.


	•	Trust unitholders have limited ability to enforce provisions of the Net Profits Interest, and Enduro Sponsor’s liability to the trust is limited.

	•	Courts outside of Delaware may not recognize the limited liability of the trust unitholders provided under Delaware law.


	•	The operations of the Underlying Properties are subject to environmental laws and regulations that could adversely affect the cost, manner or feasibility of conducting operations on them or result in significant costs and liabilities, which could reduce the amount of cash available for distribution to trust unitholders.


	•	The operations of the Underlying Properties are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting operations on them or expose the operator to significant liabilities, which could reduce the amount of cash available for distribution to trust unitholders.


	•	Climate change laws and regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas that the operators produce while the physical effects of climate change could disrupt their production and cause them to incur significant costs in preparing for or responding to those effects.

	•	Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect the services of the operators of the Underlying Properties.

	•	The bankruptcy of Enduro Sponsor or any of the Third Party Operators could impede the operation of the wells and the development of the proved undeveloped reserves.


	•	In the event of the bankruptcy of Enduro Sponsor, if a court held that the Net Profits Interest was part of the bankruptcy estate, the trust may be treated as an unsecured creditor with respect to the Net Profits Interest attributable to properties in Louisiana and New Mexico.


	•	Adverse developments in Texas, Louisiana or New Mexico could adversely impact the results of operations and cash flows of the Underlying Properties and reduce the amount of cash available for distributions to trust unitholders.

	•	The receipt of payments by Enduro Sponsor based on the hedge contracts depends upon the financial position of the hedge contract counterparties. A default by any of the hedge contract counterparties could reduce the amount of cash available for distribution to the trust unitholders.

	•	The tax treatment of an investment in trust units could be affected by recent and potential legislative changes, possibly on a retroactive basis.


	•	The trust has not requested a ruling from the Internal Revenue Service (the “IRS”) regarding the tax treatment of the trust. If the IRS were to determine (and be sustained in that determination) that the trust is not a “grantor trust” for federal income tax purposes, the trust could be subject to more complex and costly tax reporting requirements that could reduce the amount of cash available for distribution to trust unitholders.


	•	Certain U.S. federal income tax preferences currently available with respect to oil and natural gas production may be eliminated as a result of future legislation.


	•	You will be required to pay taxes on your share of the trust’s income even if you do not receive any cash distributions from the trust.


	•	A portion of any tax gain on the disposition of the trust units could be taxed as ordinary income.


	•	The trust will allocate its items of income, gain, loss and deduction between transferors and transferees of the trust units each month based upon the ownership of the trust units on the monthly record date, instead of on the basis of the date a particular trust unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among the trust unitholders.

Summary Unaudited Pro Forma Combined Financial and Operating Data of the Underlying Properties and Unaudited Pro Forma Distributable Income of the Trust

Unaudited Pro Forma Combined Financial Data of the Underlying Properties

The summary unaudited pro forma combined financial data presented below should be read in conjunction with “The Underlying Properties — Unaudited Pro Forma Combined Financial and Operating Data of the Underlying Properties,” “The Underlying Properties — Discussion and Analysis of Pro Forma Combined Historical Results of the Underlying Properties” and the accompanying financial statements and related notes included elsewhere in this prospectus. The following table sets forth the combined revenues, direct operating expenses and the excess of revenues over direct operating expenses of all the Underlying Properties as if they had been owned by Enduro Sponsor as of January 1, 2010. The summary unaudited pro forma combined financial data have been derived from the unaudited pro forma statements of historical revenues and direct operating expenses of the Underlying Properties included elsewhere in this prospectus.


	Three Months Ended		Year Ended
	March 31, 2011		December 31, 2010
	(In thousands)
	(Unaudited)

Revenues:
Oil	$	20,150	$	70,033
Natural gas		7,262		33,787

Total revenues	$	27,412	$	103,820

Direct operating expenses:
Lease operating	$	6,185	$	24,579
Gathering and processing		489		1,977
Production and other taxes		2,005		8,069

Total direct operating expenses	$	8,679	$	34,625

Excess of revenues over direct operating expenses	$	18,733	$	69,195

Unaudited Pro Forma Distributable Income of the Trust

The table below outlines the calculation of pro forma distributable income from the Net Profits Interest for the three months ended March 31, 2011 and for 2010 based on the excess of revenues over direct operating expenses of the Underlying Properties for the three months ended March 31, 2011 and for the year ended December 31, 2010, respectively, set forth above. The table below should be read in conjunction with the unaudited pro forma financial information of the trust included elsewhere in this prospectus. The pro forma amounts below do not purport to present cash available for distribution by

the trust to trust unitholders had the formation transactions contemplated actually occurred on January 1, 2010. In addition, cash available for distribution by the trust will be calculated based upon actual cash receipts of the trust during the applicable month, while the unaudited pro forma available cash calculation has been prepared using a modified cash basis of accounting. Please refer to the unaudited pro forma financial information for the trust included elsewhere in this prospectus for more information. As a result, you should view the amount of unaudited pro forma available cash only as a general indication of the amount of cash available for distribution by the trust for the three months ended March 31, 2011 and for the year ended December 31, 2010.


	Three Months Ended			Year Ended
	March 31, 2011			December 31, 2010
	(In thousands, except per unit data)
	(Unaudited)

Excess of revenues over direct operating expenses	$	18,733		$	69,195
Less development expenses		12,105			37,036

Excess of revenues over direct operating expenses and development expenses	$	6,628		$	32,159
Times Net Profits Interest		80	%		80	%

Income from Net Profits Interest	$	5,302		$	25,727

Pro forma adjustments:
Less estimated trust general and administrative expenses	$	213		$	850

Distributable income	$	5,089		$	24,877

Distributable income per trust unit	$	[ ]		$	[ ]

Pro Forma Combined Operating Data of the Underlying Properties

The following table provides the pro forma combined oil and natural gas sales volumes, average sales prices, average costs per Boe and capital expenditures for the Underlying Properties for the three months ended March 31, 2011 and 2010 and for the years ended December 31, 2010, 2009 and 2008. This pro forma combined operating data includes the effect of the Acquired Properties for all periods presented.


	Three Months Ended
	March 31,				Year Ended December 31,
	2011		2010		2010		2009		2008
					(Unaudited)

Operating Data:
Sales volumes:
Oil (MBbls)		230		239		939		1,016		1,084
Natural gas (MMcf)		1,619		1,768		7,171		8,455		8,868
Total sales (MBoe)		500		534		2,134		2,425		2,562
Average sales prices:
Oil (per Bbl)	$	87.61	$	72.61	$	74.58	$	54.44	$	98.52
Natural gas (per Mcf)		4.49		5.56		4.71		3.91		8.57
Average costs per Boe:
Lease operating	$	12.37	$	11.62	$	11.52	$	10.65	$	11.45
Gathering and processing		0.98		0.79		0.93		0.78		1.18
Production and other taxes		4.01		3.58		3.78		3.10		4.38
Capital expenditures (in thousands):
Property development costs	$	12,105	$	1,781	$	37,036	$	18,532	$	65,571

Summary Historical and Unaudited Pro Forma Financial Data of Enduro Sponsor

The summary historical audited financial data of the Predecessor as of and for the year ended December 31, 2010 have been derived from the audited financial statements of the Predecessor included elsewhere in this prospectus. Operations of the Predecessor Properties are deemed to be the “predecessor” of Enduro Sponsor and recorded transactions are shown separately based on the ownership of the Predecessor Properties. Encore Acquisition Company (“EAC”) owned the Predecessor Properties prior to March 9, 2010, at which time Denbury Resources Inc. acquired the properties in connection with its acquisition of EAC. Enduro Sponsor then acquired the Predecessor Properties on December 1, 2010. Accordingly, the audited financial statements of the Predecessor as of and for the year ended December 31, 2010 are presented for (i) “Predecessor-EAC” for the period from January 1, 2010 through March 8, 2010; (ii) “Predecessor-DNR” for the period from March 9, 2010 through November 30, 2010 and (iii) “Enduro Sponsor” for the period from Enduro Sponsor’s inception (March 3, 2010) through December 31, 2010.

The summary historical unaudited financial data of Enduro Sponsor as of March 31, 2011 and 2010 and for the three-month period ended March 31, 2011 and 2010 have been derived from Enduro Sponsor’s unaudited interim financial statements. The unaudited financial statements were prepared on a basis consistent with the audited statements and, in the opinion of Enduro Sponsor’s management, include all adjustments (consisting only of normal recurring adjustments) necessary to present fairly the results of Enduro Sponsor for the periods presented.

The summary unaudited pro forma financial data as of and for the three months ended March 31, 2011 and for the year ended December 31, 2010 set forth in the following table has been derived from the unaudited pro forma financial statements of Enduro Sponsor included elsewhere in this prospectus. The pro forma adjustments have been prepared as if the acquisition of the Acquired Properties and, with respect to the pro forma as adjusted information, the conveyance of the Net Profits Interest and the offer and sale of the trust units and application of the net proceeds therefrom, had taken place (i) on March 31, 2011, in the case of the pro forma balance sheet information as of March 31, 2011, and (ii) as of January 1, 2010, in the case of the pro forma statements of earnings for the three months ended March 31, 2011 and for the year ended December 31, 2010.


				Enduro
				Sponsor						Enduro
	Enduro			Pro Forma						Sponsor
	Sponsor			as Adjusted						Pro Forma
	Pro Forma			for the Offering			Enduro			as Adjusted
	for the			(Including the			Sponsor			for the Offering
	Acquisition			Conveyance of			Pro Forma for the			(including the
	of the			Net Profits			Acquisition of the			Conveyance of the		Enduro Sponsor						Enduro Sponsor			Predecessor-DNR			Predecessor-EAC
	Acquired Properties			Interest)			Acquired Properties			Net Profits Interest)		Three Months			Inception			Inception			March 9, 2010			January 1,
	Three Months Ended			Three Months Ended			Year Ended			Year Ended		Ended			Through			Through			Through			2010
	March 31,			March 31,			December 31,			December 31,		March 31,			March 31,			December 31,			November 30,			Through
	2011			2011			2010			2010		2011			2010			2010			2010			March 8, 2010
(In thousands)	(Unaudited)			(Unaudited)			(Unaudited)			(Unaudited)		(Unaudited)			(Unaudited)
Revenues	$	33,793		$	31,142		$	137,712		$	124,848	$	22,952		$	—		$	3,975		$	40,210		$	12,164
Net income (loss)	$	(9,559	)	$	(5,847	)	$	(8,645	)	$	6,185	$	(11,495	)	$	(77	)	$	(8,222	)	$	(19,515	)	$	(17,821	)
Total assets (at period end)				$	610,335							$	735,806		$	100		$	361,832		$	397,314		$	313,106
Long-term liabilities, excluding current maturities (at period end)				$	27,392							$	260,392		$	—		$	66,211		$	587		$	1,412
Members’ equity/owners’ equity				$	552,672							$	445,143		$	23		$	273,939		$	374,731		$	290,073

Summary Projected Cash Distributions

The following table presents a calculation of forecasted cash distributions to holders of trust units for the twelve months ending September 30, 2012, which was prepared by Enduro Sponsor based

on the assumptions that are described below and in “Projected Cash Distributions— Significant Assumptions Used to Prepare the Projected Cash Distributions.”

Typically, cash payment is received by Enduro Sponsor for oil production 30 to 60 days after it is produced and for natural gas production 60 to 90 days after it is produced. Given that the trust is entitled to production effective May 1, 2011 and the initial distribution will not occur until October 2011, the initial distribution in October 2011 may relate to net profits received from production from May and June of 2011. The forecasted cash distributions assume that each of the other monthly distributions during the forecasted period will relate to production from a single month. To adjust for the lag between the timing of production and the timing of cash received by Enduro Sponsor and the trust, the forecasted cash distributions for the twelve months ending September 30, 2012 are based on estimated production of oil and natural gas for the twelve months ending April 30, 2012.

Enduro Sponsor does not as a matter of course make public projections as to future sales, earnings or other results. However, the management of Enduro Sponsor has prepared the projected financial information set forth below to present the projected cash distributions to the holders of the trust units based on the estimates and hypothetical assumptions described below. The accompanying projected financial information was not prepared with a view toward complying with the published guidelines of the SEC or guidelines established by the American Institute of Certified Public Accountants with respect to projected financial information.

In the view of Enduro Sponsor’s management, the accompanying unaudited projected financial information was prepared on a reasonable basis and reflects the best currently available estimates and judgments of Enduro Sponsor related to oil and natural gas production, operating expenses and development expenses, and other general and administrative expenses based on:


	•	the oil and natural gas production estimates for the twelve months ending April 30, 2012 contained in the reserve reports;

	•	estimated direct operating expenses and development expenses for the twelve months ending April 30, 2012 contained in the reserve reports;


	•	projected payments made or received pursuant to the hedge contracts for the twelve months ending April 30, 2012;


	•	estimated general and administrative expenses of $850,000 for the twelve months ending April 30, 2012; and


	•	an adjustment for the estimated production, revenue, operating expenses and development expenses (as adjusted to reflect that Enduro Sponsor has agreed to pay for $7.2 million of development expenses otherwise attributable to the trust) expected in the twelve months ending April 30, 2012 for drilling projects in the Haynesville Shale that are not included in the reserve reports.

The projected financial information was also based on the hypothetical assumption that prices for oil and natural gas remain constant at $100.00 per Bbl of oil and $4.50 per MMBtu of natural gas during the twelve months ending April 30, 2012. These hypothetical prices are then adjusted to take into account Enduro Sponsor’s estimate of the basis differential (based on location and quality of the production) between published prices and the prices actually received by Enduro Sponsor. Actual prices paid for oil and natural gas expected to be produced from the Underlying Properties during the twelve months ending April 30, 2012 will likely differ from these hypothetical prices due to fluctuations in the prices generally experienced with respect to the production of oil and natural gas and variations in basis differentials. For example, for the twelve months ending April 30, 2011, the published daily average closing NYMEX crude oil spot price per Bbl was approximately $85.35 and the daily average NYMEX natural gas spot price per MMBtu was approximately $4.16.

Please read “Projected Cash Distributions — Significant Assumptions Used to Prepare the Projected Cash Distributions” and “Risk Factors — Prices of oil and natural gas fluctuate, and lower prices could reduce proceeds to the trust and cash distributions to trust unitholders.”

Neither Enduro Sponsor’s independent auditors nor any other independent accountants have compiled, examined or performed any procedures with respect to the projected financial information contained herein, nor have they expressed any opinion or any other form of assurance on such information or its achievability, and assume no responsibility for, and disclaim any association with, the projected financial information.

The projections and estimates and the hypothetical assumptions on which they are based are subject to significant uncertainties, many of which are beyond the control of Enduro Sponsor or the trust. Actual cash distributions to trust unitholders, therefore, could vary significantly based upon events or conditions occurring that are different from the events or conditions assumed to occur for purposes of these projections. Cash distributions to trust unitholders will be particularly sensitive to fluctuations in oil and natural gas prices. Please read “Risk Factors — Prices of oil and natural gas fluctuate, and lower prices could reduce proceeds to the trust and cash distributions to trust unitholders.” As a result of typical production declines for oil and natural gas properties, production estimates generally decrease from year to year, and the projected cash distributions shown in the table below are not necessarily indicative of distributions for future years. Please read “Projected Cash Distributions — Sensitivity of Projected Cash Distributions to Oil and Natural Gas Production and Prices,” which shows projected effects on cash distributions from hypothetical changes in oil and natural gas production and prices. Because payments to the trust will be generated by depleting assets and the trust has a finite life with the production from the Underlying Properties diminishing over time, a portion of each distribution will represent, in effect, a return of your original investment. Please read “Risk Factors — The reserves attributable to the Underlying Properties are depleting assets and production from those reserves will diminish over time. Furthermore, the trust is precluded from acquiring other oil and natural gas properties or net profits interests to replace the depleting assets and production. Therefore, proceeds to the trust and cash distributions to trust unitholders will decrease over time.”


	Projections for the Twelve
	Month Period Ending
Projected Cash Distributions to Trust Unitholders	September 30, 2012
	(In thousands,
	except per unit data)

Underlying Properties sales volumes:
Oil (MBbl)⁽¹⁾		911
Natural gas (MMcf)		7,119

Total sales (MBoe)		2,097

Assumed NYMEX price⁽²⁾:
Oil (per Bbl)	$	100.00
Natural gas (per MMBtu)		4.50
Assumed realized sales price⁽³⁾:
Oil (per Bbl)	$	96.54
Natural gas (per Mcf)		4.63
Calculation of net profits:
Gross profits⁽⁴⁾:
Oil sales	$	87,940
Natural gas sales		32,979

Total		120,919

Costs:
Direct operating expenses:
Lease operating expenses	$	23,489
Production and other taxes		9,225
Development expenses⁽⁵⁾		14,000

Total		46,714

Settlement of hedge contracts⁽⁶⁾		830

Net adjustment for additional projects⁽⁷⁾		(989	)
Net profits		74,046

Percentage allocable to Net Profits Interest		80%

Net profits to trust from Net Profits Interest	$	59,237

Trust general and administrative expenses⁽⁸⁾		850

Cash available for distribution by the trust	$	58,387

Cash distribution per trust unit (assumes [ ] units)	$	[ ]


⁽¹⁾		Sales volumes for oil include 9 MBbls of NGLs.

⁽²⁾		For a description of the effect of lower NYMEX prices on projected cash distributions, please read “Projected Cash Distributions — Sensitivity of Projected Cash Distributions to Oil and Natural Gas Production and Prices.”


⁽³⁾		Sales price net of forecasted gravity, quality, transportation, gathering and processing and marketing costs. For more information about the estimates and hypothetical assumptions made in preparing the table above, see “Projected Cash Distributions — Significant Assumptions Used to Prepare the Projected Cash Distributions.”


⁽⁴⁾		Represents “gross profits” as described in “Computation of Net Profits.”


⁽⁵⁾		Does not include development expenses related to 21 gross (2.4 net) wells associated with development drilling projects in the Haynesville Shale. Please read footnote 7.


⁽⁶⁾		Reflects net cash impact of settlements of hedge contracts relating to production. See “The Underlying Properties — Hedge Contracts.”


⁽⁷⁾		Net adjustment for additional projects reflects the expected drilling of 21 gross (2.4 net) wells in the Haynesville Shale during the forecast period associated with development drilling projects not reflected in the reserve reports but for which notifications have been received by Enduro Sponsor as of June 2011. These additional development drilling projects are expected to increase total sales volumes by 221 MBoe, total gross profits by $3.3 million and total lease operating and development expenses and production and other taxes by $4.3 million, which is expected to result in a decrease in net profits for the Underlying Properties by $989,000 and cash available for distribution to the trust by $791,000. The amount of estimated development expenses has been adjusted to reflect the agreement by Enduro Sponsor to pay for up to $9.0 million (or $7.2 million attributable to the trust’s Net Profits Interest) of the total estimated development expenses of $11.9 million related to the 21 gross (2.4 net) wells, thereby reducing the trust’s share of development expenses associated with these wells to $2.3 million. In the absence of this payment obligation by Enduro Sponsor, the cash available for distribution to the trust would be reduced by an additional $7.2 million during the forecast period. Please read “Projected Cash Distributions — Significant Assumptions Used to Prepare the Projected Cash Distributions — Net adjustment for additional projects.”


⁽⁸⁾		Total general and administrative expenses of the trust on an annualized basis for the twelve months ending April 30, 2012 are expected to be $850,000 and will include the annual fees to the trustees, accounting fees, engineering fees, legal fees, printing costs and other expenses properly chargeable to the trust.

Enduro Sponsor

Enduro Sponsor is a privately-held Delaware limited liability company engaged in the production and development of oil and natural gas from properties located in Texas, Louisiana and New Mexico. Enduro Sponsor was formed on March 3, 2010.

As of December 31, 2010, Enduro Sponsor held interests in approximately 4,866 gross (919 net) producing wells, and had proved reserves of approximately 32.8 MMBoe.

After giving pro forma effect to the conveyance of the Net Profits Interest to the trust, the offering of the trust units contemplated by this prospectus and the application of the net proceeds as described in “Use of Proceeds,” as of March 31, 2011, Enduro Sponsor would have had total assets of $610.3 million and total liabilities of $57.7 million. For an explanation of the pro forma adjustments, please read “Financial Statements of Enduro Sponsor — Unaudited Pro Forma Financial Statements — Introduction.”

The address of Enduro Sponsor is 777 Main Street, Suite 800, Fort Worth, Texas 76102, and its telephone number is (817) 744-8200.

The Offering


Trust units offered by Enduro Sponsor		[ ] trust units, or [ ] trust units if the underwriters exercise their option to purchase additional trust units in full


Trust units owned by Enduro Sponsor after the offering		[ ] trust units, or [ ] trust units if the underwriters exercise their option to purchase additional trust units in full


Trust units outstanding after the offering		[ ] trust units


Use of proceeds		Enduro Sponsor is offering all of the trust units to be sold in this offering, including the trust units to be sold upon any exercise of the underwriters’ option to purchase additional trust units. The estimated net proceeds of this offering to be received by Enduro Sponsor will be approximately $ million, after deducting underwriting discounts and commissions, structuring fees and expenses, and $ million if the underwriters exercise their option to purchase additional trust units in full. Enduro Sponsor intends to use the net proceeds from this offering, including any proceeds from the exercise of the underwriters’ option to purchase additional trust units, to repay amounts outstanding under its senior secured credit agreement and for general limited liability company purposes, which may include additional acquisitions. Enduro Sponsor is deemed to be an underwriter with respect to the trust units offered hereby. Please read “Use of Proceeds.”


Proposed NYSE symbol		“NDRO”


Monthly cash distributions		The trust will pay monthly distributions to the holders of trust units as of the applicable record date (generally the 15th day of each calendar month) on or before the 10th business day after the record date. The first distribution from the trust to the trust unitholders will be made on or about October 28, 2011 to trust unitholders owning trust units on or about October 14, 2011.


		Actual cash distributions to the trust unitholders will fluctuate monthly based upon the quantity of oil and natural gas produced from the Underlying Properties, the prices received for oil and natural gas production and other factors. Because payments to the trust will be generated by depleting assets with the production from the Underlying Properties diminishing over time, a portion of each distribution will represent, in effect, a return of your original investment. Oil and natural gas production from proved reserves attributable to the Underlying Properties is expected to decline over time. Please read “Risk Factors.”

Dissolution of the trust		The trust will dissolve upon the earliest to occur of the following: (1) the trust, upon approval of the holders of at


		least 75% of the outstanding trust units, sells the Net Profits Interest, (2) the annual cash available for distribution to the trust is less than $2 million for each of any two consecutive years, (3) the holders of at least 75% of the outstanding trust units vote in favor of dissolution or (4) the trust is judicially dissolved.


Estimated ratio of taxable income to distributions		Enduro Sponsor estimates that a trust unitholder who owns the trust units purchased in this offering through the record date for distribution for the period ending December 31, 20[ ], will recognize, on a cumulative basis, an amount of federal taxable income for that period of approximately [ ]% of the cash distributed to such trust unitholder with respect to that period. Please read “Federal Income Tax Consequences — U.S. Federal Income Tax Consequences — Direct Taxation of Trust Unitholders” for the basis of this estimate.


Summary of income tax consequences		Trust unitholders will be taxed directly on the income from assets of the trust. Enduro Sponsor and the trust intend to treat the Net Profits Interest, which will be granted to the trust on a perpetual basis, as a mineral royalty interest that generates ordinary income subject to depletion for U.S. federal income tax purposes. Please read “Federal Income Tax Consequences.”

RISK FACTORS

Prices of oil and natural gas fluctuate, and lower prices could reduce proceeds to the trust and cash distributions to trust unitholders.

The trust’s reserves and monthly cash distributions are highly dependent upon the prices realized from the sale of oil and natural gas. Prices of oil and natural gas can fluctuate widely on a month-to-month basis in response to a variety of factors that are beyond the control of the trust and Enduro Sponsor. These factors include, among others:


	•	regional, domestic and foreign supply and perceptions of supply of oil and natural gas;

	•	the level of demand and perceptions of demand for oil and natural gas;

	•	political conditions or hostilities in oil and natural gas producing countries;

	•	anticipated future prices of oil and natural gas and other commodities;

	•	weather conditions and seasonal trends;

	•	technological advances affecting energy consumption and energy supply;

	•	U.S. and worldwide economic conditions;

	•	the price and availability of alternative fuels;

	•	the proximity, capacity, cost and availability of gathering and transportation facilities;

	•	the volatility and uncertainty of regional pricing differentials;

	•	governmental regulations and taxation;

	•	energy conservation and environmental measures; and

	•	acts of force majeure.

Crude oil prices declined from record high levels in early July 2008 of over $140 per Bbl to below $45 per Bbl in February 2009 before rebounding to over $110 per Bbl in May 2011. Natural gas prices declined from over $13.57 per MMBtu in July 2008 to below $3.30 per MMBtu in October 2010 before rebounding to over $4.60 per MMBtu in May 2011.

Lower prices of oil and natural gas will reduce profits to which the trust is entitled and may ultimately reduce the amount of oil and natural gas that is economic to produce from the Underlying Properties. As a result, the operators of the Underlying Properties could determine during periods of low commodity prices to shut in or curtail production from wells on the Underlying Properties. In addition, the operators could determine during periods of low commodity prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, an operator may abandon any well or property if it reasonably believes that the well or property can no longer produce oil or natural gas in commercially paying quantities. This could result in termination of the Net Profits Interest relating to the abandoned well or property.

The Underlying Properties are sensitive to decreasing commodity prices. The commodity price sensitivity is due to a variety of factors that vary from well to well, including the costs associated with water handling and disposal, chemicals, surface equipment maintenance, downhole casing repairs and reservoir pressure maintenance activities that are necessary to maintain production. As a result, the volatility of commodity prices may cause the expenses of certain wells to exceed the well’s revenue. If this scenario were to occur, the operator may decide to shut-in the well or plug and abandon the well. This scenario could reduce future cash distributions to trust unitholders.

Enduro Sponsor has entered into hedge contracts with respect to approximately 70%, 76% and 67% of expected production of oil and natural gas for 2011, 2012 and 2013, respectively, from the

proved developed reserves attributable to the Underlying Properties in the reserve reports. The hedge contracts are intended to reduce exposure of the revenues from oil and natural gas production from the Underlying Properties to fluctuations in oil and natural gas prices and to achieve more predictable cash flow. Some of the hedge contracts could limit the benefit to the trust of any increase in oil or natural gas prices through 2013. The trust will be required to bear its share of the hedge payments regardless of whether the corresponding quantities of oil and natural gas are produced or sold. Furthermore, Enduro Sponsor has not entered into any hedge contracts relating to oil and natural gas volumes expected to be produced after 2013, and the terms of the conveyance of the Net Profits Interest will prohibit Enduro Sponsor from entering into new hedging arrangements burdening the trust following the completion of this offering. As a result, the amount of the cash distributions will be subject to a greater fluctuation after 2013 due to changes in oil and natural gas prices. For a discussion of the hedge contracts, please read “The Underlying Properties — Hedge Contracts.”

Estimates of future cash distributions to trust unitholders are based on assumptions that are inherently subjective.

The projected cash distributions to trust unitholders for the twelve months ending September 30, 2012 contained elsewhere in this prospectus are based on Enduro Sponsor’s calculations, and Enduro Sponsor has not received an opinion or report on such calculations from any independent accountants or engineers. Such calculations are based on assumptions about drilling, production, crude oil and natural gas prices, hedging activities, development expenses, and other matters that are inherently uncertain and are subject to significant business, economic, financial, legal, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those estimated. In particular, these estimates have assumed that crude oil and natural gas production is sold in 2011 and 2012 based on assumed NYMEX prices of $100.00 per Bbl in the case of crude oil and $4.50 per MMBtu in the case of natural gas. However, actual sales prices may be significantly lower. Additionally, these estimates assume the Underlying Properties will achieve production volumes set forth in the reserve reports; however, actual production volumes may be significantly lower. If prices or production are lower than expected, the amount of cash available for distribution to trust unitholders would be reduced. Furthermore, there have been an additional 21 gross (2.4 net) wells spud or proposed and approved by Enduro Sponsor in 2011 that are not represented in the reserve report because they would not be classified as proved locations but would rather be classified as probable locations based on the information available on December 31, 2010. Although Enduro Sponsor has agreed to pay up to $9.0 million of the development expenses associated with these wells incurred after May 1, 2011, Enduro Sponsor will not pay any amounts in excess of $9.0 million, even if future capital expenditures increase substantially. Thus, any additional drilling opportunities not reflected in the reserve reports could increase development expenses significantly without an immediate increase in production or revenues, which could decrease the amount of cash available for distribution to trust unitholders unless and until production and revenue from the new wells resulted in the recoupment of such expenses.

Actual reserves and future production may be less than current estimates, which could reduce cash distributions by the trust and the value of the trust units.

The value of the trust units and the amount of future cash distributions to the trust unitholders will depend upon, among other things, the accuracy of the reserves and future production estimated to be attributable to the trust’s interest in the Underlying Properties. Please read “The Underlying Properties — Reserve Reports” for a discussion of the method of allocating proved reserves to the Underlying Properties and the Net Profits Interest. It is not possible to measure underground accumulations of oil and natural gas in an exact way, and estimating reserves is inherently uncertain. Ultimately, actual production and revenues for the Underlying Properties could vary both positively and negatively and in material amounts from estimates. Furthermore, direct operating expenses and development expenses relating to the Underlying Properties could be substantially higher than current

estimates. Petroleum engineers are required to make subjective estimates of underground accumulations of oil and natural gas based on factors and assumptions that include:


	•	historical production from the area compared with production rates from other producing areas;

	•	oil and natural gas prices, production levels, Btu content, production expenses, transportation costs, severance and excise taxes and development expenses; and

	•	the assumed effect of expected governmental regulation and future tax rates.

Changes in these assumptions and amounts of actual direct operating expenses and development expenses could materially decrease reserve estimates. In addition, the quantities of recovered reserves attributable to the Underlying Properties may decrease in the future as a result of future decreases in the price of oil or natural gas.

The Third Party Operators are the operators of approximately 99.3% of the wells on the Underlying Properties and, therefore, Enduro Sponsor is not in a position to control the timing of development efforts, the associated costs or the rate of production of the reserves on such properties.

As of December 31, 2010, approximately 99.3% of the wells on the Underlying Properties were operated by the Third Party Operators. As a result, Enduro Sponsor has limited ability to exercise influence over, and control the risks or costs associated with, the operations of these properties. The failure of a Third Party Operator to adequately or efficiently perform operations, a Third Party Operator’s breach of the applicable operating agreements or a Third Party Operator’s failure to act in ways that are in Enduro Sponsor’s or the trust’s best interests could reduce production and revenues. Further, none of the Third Party Operators of the Underlying Properties are obligated to undertake any development activities, so any development and production activities will be subject to their reasonable discretion. The success and timing of drilling and development activities on properties operated by the Third Party Operators, therefore, depends on a number of factors that will be largely outside of Enduro Sponsor’s control, including:


	•	the timing and amount of capital expenditures, which could be significantly more than anticipated;


	•	the availability of suitable drilling equipment, production and transportation infrastructure and qualified operating personnel;

	•	the Third Party Operator’s expertise, operating efficiency and financial resources;

	•	approval of other participants in drilling wells;

	•	the selection of technology;

	•	the selection of counterparties for the sale of production; and

	•	the rate of production of the reserves.

The Third Party Operators may elect not to undertake development activities, or may undertake such activities in an unanticipated fashion, which may result in significant fluctuations in capital expenditures and amounts available for distribution to trust unitholders.

Developing oil and natural gas wells and producing oil and natural gas are costly and high-risk activities with many uncertainties that could adversely affect future production from the Underlying Properties. Any delays, reductions or cancellations in development and producing activities could decrease revenues that are available for distribution to trust unitholders.

The process of developing oil and natural gas wells and producing oil and natural gas on the Underlying Properties is subject to numerous risks beyond the trust’s, Enduro Sponsor’s and the Third Party Operators’ control, including risks that could delay the operators’ current drilling or production

schedule and the risk that drilling will not result in commercially viable oil or natural gas production. The ability of the operators to carry out operations or to finance planned development expenses could be materially and adversely affected by any factor that may curtail, delay, reduce or cancel development and production, including:


	•	delays imposed by or resulting from compliance with regulatory requirements, including permitting;

	•	unusual or unexpected geological formations;

	•	shortages of or delays in obtaining equipment and qualified personnel;

	•	lack of available gathering facilities or delays in construction of gathering facilities;

	•	lack of available capacity on interconnecting transmission pipelines;

	•	equipment malfunctions, failures or accidents;

	•	unexpected operational events and drilling conditions;

	•	reductions in oil or natural gas prices;

	•	market limitations for oil or natural gas;

	•	pipe or cement failures;

	•	casing collapses;

	•	lost or damaged drilling and service tools;

	•	loss of drilling fluid circulation;

	•	uncontrollable flows of oil and natural gas, insert gas, water or drilling fluids;

	•	fires and natural disasters;

	•	environmental hazards, such as oil and natural gas leaks, pipeline ruptures and discharges of toxic gases;

	•	adverse weather conditions; and

	•	oil or natural gas property title problems.

In the event that planned operations, including drilling of development wells, are delayed or cancelled, or existing wells or development wells have lower than anticipated production due to one or more of the factors above or for any other reason, estimated future distributions to trust unitholders may be reduced. In the event an operator incurs increased costs due to one or more of the above factors or for any other reason and is not able to recover such costs from insurance, the estimated future distributions to trust unitholders may be reduced.

The trust is passive in nature and neither the trust nor the trust unitholders will have any ability to influence Enduro Sponsor or control the operations or development of the Underlying Properties.

The trust units are a passive investment that entitle the trust unitholder to only receive cash distributions from the Net Profits Interest and hedge contracts being conveyed to the trust. Trust unitholders have no voting rights with respect to Enduro Sponsor and, therefore, will have no managerial, contractual or other ability to influence Enduro Sponsor’s or the Third Party Operators’ activities or the operations of the Underlying Properties. Oil and natural gas properties are typically managed pursuant to an operating agreement among the working interest owners of oil and natural gas properties. The Third Party Operators operate approximately 99.3% of the wells on the Underlying Properties. The typical operating agreement contains procedures whereby the owners of the working interests in the property designate one of the interest owners to be the operator of the property. Under these arrangements, the operator is typically responsible for making all decisions relating to drilling

activities, sale of production, compliance with regulatory requirements and other matters that affect the property.

Shortages of equipment, services and qualified personnel could increase costs of developing and operating the Underlying Properties and result in a reduction in the amount of cash available for distribution to the trust unitholders.

The demand for qualified and experienced personnel to conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Historically, there have been shortages of drilling rigs and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher oil and natural gas prices generally stimulate demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services. Shortages of field personnel and equipment or price increases could hinder the ability of the operators of the Underlying Properties to conduct the operations which they currently have planned for the Underlying Properties, which would reduce the amount of cash received by the trust and available for distribution to the trust unitholders.

The trust units may lose value as a result of title deficiencies with respect to the Underlying Properties.

Enduro Sponsor acquired the Underlying Properties through various acquisitions since December 2010. The existence of a material title deficiency with respect to the Underlying Properties could reduce the value of a property or render it worthless, thus adversely affecting the Net Profits Interest and the distributions to trust unitholders. Enduro Sponsor does not obtain title insurance covering mineral leaseholds, and Enduro Sponsor’s failure to cure any title defects may cause Enduro Sponsor to lose its rights to production from the Underlying Properties. In the event of any such material title problem, profits available for distribution to trust unitholders and the value of the trust units may be reduced.

Enduro Sponsor may transfer all or a portion of the Underlying Properties at any time without trust unitholder consent, subject to specified limitations.

Enduro Sponsor may at any time transfer all or part of the Underlying Properties, subject to and burdened by the Net Profits Interest, and may, along with the Third Party Operators, abandon individual wells or properties reasonably believed to be uneconomic. Trust unitholders will not be entitled to vote on any transfer or abandonment of the Underlying Properties, and the trust will not receive any profits from any such transfer, except in the limited circumstances when the Net Profits Interest is released in connection with such transfer, in which case the trust will receive an amount equal to the fair market value (net of sales costs) of the Net Profits Interest released. Please read “The Underlying Properties — Sale and Abandonment of Underlying Properties.” Following any sale or transfer of any of the Underlying Properties, if the Net Profits Interest is not released in connection with such sale or transfer, the Net Profits Interest will continue to burden the transferred property and net profits attributable to such property will be calculated as part of the computation of net profits described in this prospectus. Enduro Sponsor may delegate to the transferee responsibility for all of Enduro Sponsor’s obligations relating to the Net Profits Interest on the portion of the Underlying Properties transferred.

In addition, Enduro Sponsor may, without the consent of the trust unitholders, require the trust to release the Net Profits Interest associated with any lease that accounts for less than or equal to 0.25% of the total production from the Underlying Properties in the prior 12 months and provided that the Net Profits Interest covered by such releases cannot exceed, during any 12-month period, an aggregate fair market value to the trust of $500,000. These releases will be made only in connection with a sale by Enduro Sponsor of the relevant Underlying Properties and are conditioned upon the

trust’s receiving an amount equal to the fair market value of such Net Profits Interest. Enduro Sponsor has not identified for sale any of the Underlying Properties.

The Third Party Operators and Enduro Sponsor may enter into farm-out, operating, participation and other similar agreements to develop the property without the consent or approval of the trustee or any trust unitholder.

The reserves attributable to the Underlying Properties are depleting assets and production from those reserves will diminish over time. Furthermore, the trust is precluded from acquiring other oil and natural gas properties or net profits interests to replace the depleting assets and production. Therefore, proceeds to the trust and cash distributions to trust unitholders will decrease over time.

The profits payable to the trust attributable to the Net Profits Interest are derived from the sale of production of oil and natural gas from the Underlying Properties. The reserves attributable to the Underlying Properties are depleting assets, which means that the reserves and the quantity of oil and natural gas produced from the Underlying Properties will decline over time. Based on the estimated production and operating expenses in the reserve report of the Underlying Properties, the oil and natural gas production from proved reserves attributable to the Underlying Properties is projected to be shallow declining over the next five years. Actual decline rates may vary from this projected decline rate. In the event expected future development is delayed, reduced or cancelled, the average rate of decline will likely exceed 9% per year.

Future maintenance projects on the Underlying Properties may affect the quantity of proved reserves that can be economically produced from wells on the Underlying Properties. The timing and size of these projects will depend on, among other factors, the market prices of oil and natural gas. Neither Enduro Sponsor nor, to Enduro Sponsor’s knowledge, the Third Party Operators have a contractual obligation to develop or otherwise pay development expenses on the Underlying Properties in the future. Enduro Sponsor, however, will have an obligation to pay up to $9.0 million of development expenses (or $7.2 million attributable to the trust’s 80% indirect interest in the Underlying Properties) for projects in the Haynesville Shale for which notifications have been received by Enduro Sponsor as of June 2011, and which are a part of Enduro Sponsor’s $30 million 2011 capital budget for the Underlying Properties. Furthermore, with respect to properties for which Enduro Sponsor is not designated as the operator, Enduro Sponsor has limited control over the timing or amount of those development expenses. Enduro Sponsor also has the right to non-consent and not participate in the development expenses on properties for which it is not the operator, in which case Enduro Sponsor and the trust will not receive the production resulting from such development expenses. If the operators of the Underlying Properties do not implement maintenance projects when warranted, the future rate of production decline of proved reserves may be higher than the rate currently expected by Enduro Sponsor or estimated in the reserve report.

The trust agreement will provide that the trust’s activities will be limited to owning the Net Profits Interest and any activity reasonably related to such ownership, including activities required or permitted by the terms of the conveyance related to the Net Profits Interest. As a result, the trust will not be permitted to acquire other oil and natural gas properties or net profits interests to replace the depleting assets and production attributable to the Net Profits Interest.

Because the net profits payable to the trust are derived from the sale of depleting assets, the portion of the distributions to trust unitholders attributable to depletion may be considered to have the effect of a return of capital as opposed to a return on investment. Eventually, the Underlying Properties burdened by the Net Profits Interest may cease to produce in commercially paying quantities and the trust may, therefore, cease to receive any distributions of net profits therefrom.

An increase in the differential between the price realized by Enduro Sponsor for oil or natural gas produced from the Underlying Properties and the NYMEX or other benchmark price of oil or natural gas could reduce the profits to the trust and, therefore, the cash distributions by the trust and the value of trust units.

The prices received for Enduro Sponsor’s oil and natural gas production usually fall below the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. The difference between the price received and the benchmark price is called a basis differential. The differential may vary significantly due to market conditions, the quality and location of production and other factors. Enduro Sponsor cannot accurately predict oil or natural gas differentials. Increases in the differential between the realized price of oil and natural gas and the benchmark price for oil and natural gas could reduce the profits to the trust, the cash distributions by the trust and the value of the trust units.

The amount of cash available for distribution by the trust will be reduced by the amount of any costs and expenses related to the Underlying Properties and other costs and expenses incurred by the trust.

The trust will indirectly bear an 80% share of all costs and expenses related to the Underlying Properties, such as direct operating expenses, development expenses and hedge expenses, which will reduce the amount of cash received by the trust and thereafter distributable to trust unitholders. Accordingly, higher costs and expenses related to the Underlying Properties will directly decrease the amount of cash received by the trust in respect of its Net Profits Interest. Please read “The Underlying Properties — Unaudited Pro Forma Combined Financial and Operating Data of the Underlying Properties.” Historical costs may not be indicative of future costs. For example, the Third Party Operators may in the future propose additional drilling projects that significantly increase the capital expenditures associated with the Underlying Properties, which could reduce cash available for distribution by the trust. In addition, cash available for distribution by the trust will be further reduced by the trust’s general and administrative expenses, which are expected to be approximately $850,000 for the twelve months ending April 30, 2012. For details about these general and administrative expenses, please read “Description of the Trust Agreement — Fees and Expenses.”

If direct operating expenses, development expenses and hedge expenses on the Underlying Properties together with the other costs exceed gross profits of production from the Underlying Properties, the trust will not receive net profits from those properties until future gross profits from production exceed the total of the excess costs, plus accrued interest at the prime rate. If the trust does not receive net profits pursuant to the Net Profits Interest, or if such net profits are reduced, the trust will not be able to distribute cash to the trust unitholders, or such cash distributions will be reduced, respectively. Development activities may not generate sufficient additional revenue to repay the costs.

The generation of profits for distribution by the trust depends in part on access to and operation of gathering, transportation and processing facilities. Any limitation in the availability of those facilities could interfere with sales of oil and natural gas production from the Underlying Properties.

The amount of oil and natural gas that may be produced and sold from a well is subject to curtailment in certain circumstances, such as by reason of weather conditions, pipeline interruptions due to scheduled and unscheduled maintenance, failure of tendered oil and natural gas to meet quality specifications of gathering lines or downstream transporters, excessive line pressure which prevents delivery, physical damage to the gathering system or transportation system or lack of contracted capacity on such systems. The curtailments may vary from a few days to several months. In many cases, the operators of the Underlying Properties are provided limited notice, if any, as to when production will be curtailed and the duration of such curtailments. If the operators of the Underlying Properties are forced to reduce production due to such a curtailment, the revenues of the trust and the

amount of cash distributions to the trust unitholders would similarly be reduced due to the reduction of profits from the sale of production.

The trustee must, under certain circumstances, sell the Net Profits Interest and dissolve the trust prior to the expected termination of the trust. As a result, trust unitholders may not recover their investment.

The trustee must sell the Net Profits Interest and dissolve the trust if the holders of at least 75% of the outstanding trust units approve the sale or vote to dissolve the trust. The trustee must also sell the Net Profits Interest and dissolve the trust if the annual gross profits from the Underlying Properties attributable to the Net Profits Interest are less than $2 million for each of any two consecutive years. The net profits of any such sale will be distributed to the trust unitholders.

Enduro Sponsor may sell trust units in the public or private markets, and such sales could have an adverse impact on the trading price of the trust units.

After the closing of the offering, Enduro Sponsor will hold an aggregate of [ ] trust units, assuming no exercise of the underwriters’ option to purchase additional trust units. Enduro Sponsor has agreed not to sell any trust units for a period of 180 days after the date of this prospectus without the consent of Barclays Capital Inc. Please read “Underwriting (Conflicts of Interest).” After such period, Enduro Sponsor may sell trust units in the public or private markets, and any such sales could have an adverse impact on the price of the trust units or on any trading market that may develop. The trust has granted registration rights to Enduro Sponsor, which, if exercised, would facilitate sales of trust units by Enduro Sponsor.

There has been no public market for the trust units.

The initial public offering price of the trust units will be determined by negotiation among Enduro Sponsor and the underwriters. Among the factors to be considered in determining the number of trust units to be offered hereby and the initial public offering price will be estimates of distributions to trust unitholders; overall quality of the oil and natural gas properties attributable to the Underlying Properties; the history and prospects for the energy industry; Enduro Sponsor’s financial information; the prevailing securities markets at the time of this offering and the recent market prices of, and the demand for, publicly traded units of royalty trusts. None of Enduro Sponsor, the trust or the underwriters will obtain any independent appraisal or other opinion of the value of the Net Profits Interest, other than the reserve report prepared by Cawley Gillespie.

The trading price for the trust units may not reflect the value of the Net Profits Interest held by the trust.

The trading price for publicly traded securities similar to the trust units tends to be tied to recent and expected levels of cash distributions. The amounts available for distribution by the trust will vary in response to numerous factors outside the control of the trust, including prevailing prices for sales of oil and natural gas production from the Underlying Properties and the timing and amount of direct operating expenses and development expenses. Consequently, the market price for the trust units may not necessarily be indicative of the value that the trust would realize if it sold the Net Profits Interest to a third-party buyer. In addition, such market price may not necessarily reflect the fact that since the assets of the trust are depleting assets, a portion of each cash distribution paid with respect to the trust units should be considered by investors as a return of capital, with the remainder being considered as a return on investment. As a result, distributions made to a trust unitholder over the life of these depleting assets may not equal or exceed the purchase price paid by the trust unitholder.

Conflicts of interest could arise between Enduro Sponsor and its affiliates, on the one hand, and the trust and the trust unitholders, on the other hand.

As working interest owners in, and the operators of certain wells on, the Underlying Properties, Enduro Sponsor and its affiliates could have interests that conflict with the interests of the trust and the trust unitholders. For example:


	•	Enduro Sponsor’s interests may conflict with those of the trust and the trust unitholders in situations involving the development, maintenance, operation or abandonment of certain wells on the Underlying Properties for which Enduro Sponsor acts as the operator. Enduro Sponsor may also make decisions with respect to development expenses that adversely affect the Underlying Properties. These decisions include reducing development expenses on properties for which Enduro Sponsor acts as the operator, which could cause oil and natural gas production to decline at a faster rate and thereby result in lower cash distributions by the trust in the future.

	•	Enduro Sponsor may sell some or all of the Underlying Properties without taking into consideration the interests of the trust unitholders. Such sales may not be in the best interests of the trust unitholders. These purchasers may lack Enduro Sponsor’s experience or its credit worthiness. Enduro Sponsor also has the right, under certain circumstances, to cause the trust to release all or a portion of the Net Profits Interest in connection with a sale of a portion of the Underlying Properties to which such Net Profits Interest relates. In such an event, the trust is entitled to receive the fair value (net of sales costs) of the Net Profits Interest released. Please read “The Underlying Properties — Sale and Abandonment of Underlying Properties.”


	•	Enduro Sponsor has registration rights and can sell its trust units without considering the effects such sale may have on trust unit prices or on the trust itself. Additionally, Enduro Sponsor can vote its trust units in its sole discretion without considering the interests of the other trust unitholders. Enduro Sponsor is not a fiduciary with respect to the trust unitholders or the trust and will not owe any fiduciary duties or liabilities to the trust unitholders or the trust.

The trust is managed by a trustee who cannot be replaced except by a majority vote of the trust unitholders at a special meeting, which may make it difficult for trust unitholders to remove or replace the trustee.

The affairs of the trust will be managed by the trustee. Your voting rights as a trust unitholder are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of trust unitholders or for an annual or other periodic re-election of the trustee. The trust agreement provides that the trustee may only be removed and replaced by the holders of a majority of the trust units present in person or by proxy at a meeting of such holders where a quorum is present, including trust units held by Enduro Sponsor, called by either the trustee or the holders of not less than 10% of the outstanding trust units. As a result, it will be difficult for public trust unitholders to remove or replace the trustee without the cooperation of Enduro Sponsor so long as it holds a significant percentage of total trust units.

Trust unitholders have limited ability to enforce provisions of the Net Profits Interest, and Enduro Sponsor’s liability to the trust is limited.

The trust agreement permits the trustee to sue Enduro Sponsor or any other future owner of the Underlying Properties to enforce the terms of the conveyance creating the Net Profits Interest. If the trustee does not take appropriate action to enforce provisions of the conveyance, trust unitholders’ recourse would be limited to bringing a lawsuit against the trustee to compel the trustee to take specified actions. The trust agreement expressly limits a trust unitholder’s ability to directly sue Enduro Sponsor or any other third party other than the trustee. As a result, trust unitholders will not be able to

sue Enduro Sponsor or any future owner of the Underlying Properties to enforce these rights. Furthermore, the Net Profits Interest conveyance provides that, except as set forth in the conveyance, Enduro Sponsor will not be liable to the trust for the manner in which it performs its duties in operating the Underlying Properties as long as it acts without gross negligence or willful misconduct.

Courts outside of Delaware may not recognize the limited liability of the trust unitholders provided under Delaware law.

Under the Delaware Statutory Trust Act, trust unitholders will be entitled to the same limitation of personal liability extended to stockholders of corporations for profit under the General Corporation Law of the State of Delaware. No assurance can be given, however, that the courts in jurisdictions outside of Delaware will give effect to such limitation.

The operations of the Underlying Properties are subject to environmental laws and regulations that could adversely affect the cost, manner or feasibility of conducting operations on them or result in significant costs and liabilities, which could reduce the amount of cash available for distribution to trust unitholders.

The oil and natural gas exploration and production operations on the Underlying Properties are subject to stringent and comprehensive federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations that apply to the operations on the Underlying Properties, including the requirement to obtain a permit before conducting drilling, waste disposal or other regulated activities; the restriction of types, quantities and concentrations of materials that can be released into the environment; the incurrence of significant development expenses to install pollution or safety-related controls at the operated facilities; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and the imposition of substantial liabilities for pollution resulting from operations. Numerous governmental authorities, such as the U.S. Environmental Protection Agency (“EPA”) and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, often times requiring difficult and costly actions. Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties; the imposition of investigatory or remedial obligations; and the issuance of injunctions limiting or preventing some or all of the operations on the Underlying Properties. Furthermore, the inability to comply with environmental laws and regulations in a cost-effective manner, such as removal and disposal of produced water and other generated oil and gas wastes, could impair the operators’ ability to produce oil and natural gas commercially from the Underlying Properties, which would reduce profits attributable to the Net Profits Interest.

There is inherent risk of incurring significant environmental costs and liabilities in the operations on the Underlying Properties as a result of the handling of petroleum hydrocarbons and wastes, air emissions and wastewater discharges related to operations, and historical industry operations and waste disposal practices. Under certain environmental laws and regulations, the operators could be subject to joint and several strict liability for the removal or remediation of previously released materials or property contamination regardless of whether such operators were responsible for the release or contamination or whether the operations were in compliance with all applicable laws at the time those actions were taken. Private parties, including the owners of properties upon which wells are drilled and facilities where petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. In addition, the risk of accidental spills or releases could expose the operators of the Underlying Properties to significant liabilities that could have a material adverse effect on the operators’ businesses, financial condition and results of operations and could reduce the amount of cash available for distribution to trust unitholders. Changes in environmental laws and regulations

occur frequently, and any changes that result in more stringent or costly operational control requirements or waste handling, storage, transport, disposal or cleanup requirements could require the operators of the Underlying Properties to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on their results of operations, competitive position or financial condition. The operators of the Underlying Properties may be unable to recover some or any of these costs from insurance, in which case the amount of cash received by the trust may be decreased. The trust will indirectly bear 80% of all costs and expenses paid by Enduro Sponsor, including those related to environmental compliance and liabilities associated with the Underlying Properties, including costs and liabilities resulting from conditions that existed prior to Enduro Sponsor’s acquisition of the Underlying Properties unless such costs and expenses result from the operator’s negligence or misconduct. In addition, as a result of the increased cost of compliance, the operators of the Underlying Properties may decide to discontinue drilling.

The operations of the Underlying Properties are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting operations on them or expose the operator to significant liabilities, which could reduce the amount of cash available for distribution to trust unitholders.

The production and development operations on the Underlying Properties are subject to complex and stringent laws and regulations. In order to conduct their operations in compliance with these laws and regulations, the operators of the Underlying Properties must obtain and maintain numerous permits, drilling bonds, approvals and certificates from various federal, state and local governmental authorities and engage in extensive reporting. The operators of the Underlying Properties may incur substantial costs and experience delays in order to maintain compliance with these existing laws and regulations, and the trust will bear an 80% share of these costs. In addition, the operators’ costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to their operations. Such costs could have a material adverse effect on the operators’ business, financial condition and results of operations and reduce the amount of cash received by the trust in respect of the Net Profits Interest. The operators of the Underlying Properties must also comply with laws and regulations prohibiting fraud and market manipulations in energy markets. To the extent the operators of the Underlying Properties are shippers on interstate pipelines, they must comply with the tariffs of such pipelines and with federal policies related to the use of interstate capacity, and such compliance costs will be borne in part by the trust.

Laws and regulations governing exploration and production may also affect production levels. The operators of the Underlying Properties are required to comply with federal and state laws and regulations governing conservation matters, including: provisions related to the unitization or pooling of the oil and natural gas properties; the establishment of maximum rates of production from wells; the spacing of wells; the plugging and abandonment of wells; and the removal of related production equipment. Additionally, state and federal regulatory authorities may expand or alter applicable pipeline safety laws and regulations, compliance with which may require increase capital costs on the part of the operators and third party downstream natural gas transporters. These and other laws and regulations can limit the amount of oil and natural gas the operators can produce from their wells, limit the number of wells they can drill, or limit the locations at which they can conduct drilling operations, which in turn could negatively impact trust distributions, estimated and actual future net revenues to the trust and estimates of reserves attributable to the trust’s interests.

New laws or regulations, or changes to existing laws or regulations, may unfavorably impact the operators of the Underlying Properties, could result in increased operating costs or have a material adverse effect on their financial condition and results of operations and reduce the amount of cash received by the trust. For example, Congress is currently considering legislation that, if adopted in its proposed form, would subject companies involved in oil and natural gas exploration and production activities to, among other items, additional regulation of and restrictions on hydraulic fracturing of wells, the elimination of certain U.S. federal tax incentives and deductions available to oil and natural

gas exploration and production activities and the prohibition or additional regulation of private energy commodity derivative and hedging activities. These and other potential regulations could increase the operating costs of the Underlying Properties, reduce the operators’ liquidity, delay the operators’ operations or otherwise alter the way the operators conduct their business, any of which could have a material adverse effect on the trust and the amount of cash available for distribution to trust unitholders.

Climate change laws and regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas that the operators produce while the physical effects of climate change could disrupt their production and cause them to incur significant costs in preparing for or responding to those effects.

The oil and gas industry is a direct source of certain greenhouse gas (“GHG”) emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact future operations on the Underlying Properties. On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the Earth’s atmosphere and other climate changes. Based on these findings, the agency has begun adopting and implementing regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. During 2010, the EPA adopted two sets of rules regulating GHG emissions under the Clean Air Act, one of which requires a reduction in emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. The stationary source rule “tailors” these permitting programs to apply to certain stationary sources in a multi-step process, with the largest sources first subject to permitting. Facilities required to obtain PSD permits for their GHG emissions also will be required to reduce those emissions according to “best available control technology” standards for GHG that will be established by the states or, in some instances, by the EPA on a case-by-case basis. The EPA’s rules relating to emissions of GHGs from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent the EPA from implementing, or requiring state environmental agencies to implement, the rules. These EPA rulemakings could affect the operations on the Underlying Properties or the ability of the operators of the Underlying Properties to obtain air permits for new or modified facilities. In addition, on November 30, 2010, the EPA published final regulations expanding the existing greenhouse gas monitoring and reporting rule to include onshore and offshore oil and natural gas production and onshore oil and natural gas processing, transmission, storage and distribution facilities. Reporting of GHG emissions from such facilities will be required on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011. The Underlying Properties may be subject to these requirements or become subject to them in the future.

In addition, the U.S. Congress has from time to time considered legislation to reduce emissions of GHGs, and almost half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. These reductions would be expected to cause the cost of allowances to escalate significantly over time. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise limits emissions of GHGs from the equipment or operations of the operators of the Underlying Properties could require the operators to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with their operations. Such requirements could also adversely affect demand for the oil and natural gas produced, all of which could reduce profits attributable to the Net Profits Interest and, as a result, the trust’s cash available for distribution.

Because regulation of GHG emissions is relatively new, further regulatory, legislative and judicial developments are likely to occur. Such developments may affect how these GHG initiatives will impact the operators of the Underlying Properties and the trust. Due to the uncertainties surrounding the regulation of and other risks associated with GHG emissions, Enduro Sponsor cannot predict the financial impact of related developments on the operators of the Underlying Properties or the trust.

Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on the operators’ assets and operations and, consequently, may reduce profits attributable to the Net Profits Interest and, as a result, the trust’s cash available for distribution.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect the services of the operators of the Underlying Properties.

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. However, the EPA has asserted federal regulatory authority over hydraulic fracturing involving diesel fuel under the Safe Drinking Water Act’s Underground Injection Control Program and has commenced drafting guidance for permitting authorities and the industry regarding the process for obtaining a permit for hydraulic fracturing involving diesel fuel. Industry groups have filed suit challenging the EPA’s recent decision. At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with results of the study anticipated to be available by late 2012. Other federal agencies are also examining hydraulic fracturing, including the U.S. Department of Energy (“DOE”), the U.S. Government Accountability Office and the White House Council for Environmental Quality. The U.S. Department of the Interior is also considering regulation of hydraulic fracturing activities on public lands. In addition, legislation called the Fracturing Responsibility and Awareness of Chemicals Act (“FRAC Act”) has been introduced in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Also, some states have adopted, and other states are considering adopting, regulations that could restrict or impose additional requirements relating to hydraulic fracturing in certain circumstances. For example, on June 17, 2011, Texas signed into law a bill that requires the disclosure of information regarding the substances used in the hydraulic fracturing process to the Railroad Commission of Texas (the entity that regulates oil and natural gas production) and the public. Such federal or state legislation could require the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities who could then make such information publicly available. Disclosure of chemicals used in the fracturing process could make it easier for third parties opposing hydraulic fracturing to initiate legal proceedings against producers and service providers based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is regulated at the federal level, Enduro Sponsor’s and the Third Party Operators’ fracturing activities could become subject to additional permit requirements or operational restrictions and also to associated permitting delays and potential increases in costs. Further, at least three local governments in Texas have imposed temporary moratoria on drilling permits within city limits so that local ordinances may be reviewed to assess their adequacy to address such activities, while some state and local governments in the Marcellus Shale region in Pennsylvania and New York have considered or imposed temporary moratoria on drilling operations using hydraulic fracturing until further study of the potential environmental and human health impacts by the EPA or the relevant agencies are completed. No assurance can be given as to whether or not similar measures might be considered or implemented in the jurisdictions in which the Underlying Properties are located. If new laws or regulations that significantly restrict or otherwise impact hydraulic fracturing are passed by Congress or adopted in

Texas, Louisiana or New Mexico, such legal requirements could make it more difficult or costly for Enduro Sponsor or the Third Party Operators to perform hydraulic fracturing activities and thereby could affect the determination of whether a well is commercially viable. In addition, restrictions on hydraulic fracturing could reduce the amount of oil and natural gas that the operators are ultimately able to produce in commercially paying quantities from the Underlying Properties.

The bankruptcy of Enduro Sponsor or any of the Third Party Operators could impede the operation of the wells and the development of the proved undeveloped reserves.

The value of the Net Profits Interest and the trust’s ultimate cash available for distribution will be highly dependent on the financial condition of the operators of the Underlying Properties. None of the operators of the Underlying Properties, including Enduro Sponsor, has agreed with the trust to maintain a certain net worth or to be restricted by other similar covenants, and Enduro Sponsor intends to use a portion of the net proceeds of this offering for general limited liability company purposes instead of retaining all or a portion to pay costs for the operation and development of the Underlying Properties.

The ability to develop and operate the Underlying Properties depends on the future financial condition and economic performance and access to capital of the operators of those properties, which in turn will depend upon the supply and demand for oil and natural gas, prevailing economic conditions and financial, business and other factors, many of which are beyond the control of Enduro Sponsor and the Third Party Operators. Please read “Information about Enduro Resource Partners LLC (Enduro Sponsor)” for additional information relating to Enduro Sponsor, including information relating to the business of Enduro Sponsor, historical financial statements of Enduro Sponsor and other financial information relating to Enduro Sponsor. This prospectus contains no financial information about the Third Party Operators. Enduro Sponsor will not be a reporting company following this offering and will not be required to file periodic reports with the SEC pursuant to the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Therefore, as a trust unitholder, you will not have access to financial information about Enduro Sponsor.

In the event of the bankruptcy of an operator of the Underlying Properties, the working interest owners in the affected properties will have to seek a new party to perform the development and the operations of the affected wells. The working interest owners may not be able to find a replacement driller or operator, and they may not be able to enter into a new agreement with such replacement party on favorable terms within a reasonable period of time. As a result, such a bankruptcy may result in reduced production from the reserves and decreased distributions to trust unitholders.

In the event of the bankruptcy of Enduro Sponsor, if a court held that the Net Profits Interest was part of the bankruptcy estate, the trust may be treated as an unsecured creditor with respect to the Net Profits Interest attributable to properties in Louisiana and New Mexico.

conveyance of a real property interest. While no New Mexico case has clearly defined the nature of a “net profits interest” independent of the creating instrument, New Mexico case law has held that an overriding royalty interest in a mineral lease is a real property interest under New Mexico law. The 10th Circuit Court of Appeals has held that a net profits interest is “similar to” an overriding royalty interest. Given that the conveyance of the Net Profits Interest will contain a provision stating that it is the express intent of the parties that the conveyance of the Net Profits Interest constitutes a conveyance of a royalty interest in real property, in the event of a bankruptcy on the part of Enduro Sponsor, under New Mexico law, the Net Profits Interest would likely not be treated as part of Enduro Sponsor’s bankruptcy estate. Further, it is relevant that Enduro Sponsor and the trust have structured the Net Profits Interest as an overriding royalty interest in gross production payable on the basis of net profits. Nevertheless, the outcome is not certain given that there are not any dispositive Louisiana or New Mexico Supreme Court cases directly concluding that a conveyance of a net profits interest: (i) in the case of Louisiana, constitutes the conveyance of a real right and an incorporeal immovable (similar to a real property interest) or (ii) in the case of New Mexico, the conveyance of a real property interest. As such, in a bankruptcy of Enduro Sponsor, to the extent Louisiana or New Mexico law were held to be applicable, the Net Profits Interest might be considered an asset of the bankruptcy estate and used to satisfy obligations to creditors of Enduro Sponsor, in which case the trust would be an unsecured creditor of Enduro Sponsor at risk of losing the entire value of the Net Profits Interest to senior creditors.

Adverse developments in Texas, Louisiana or New Mexico could adversely impact the results of operations and cash flows of the Underlying Properties and reduce the amount of cash available for distributions to trust unitholders.

The operations of the Underlying Properties are focused on the production and development of oil and natural gas within the states of Texas, Louisiana and New Mexico. As a result, the results of operations and cash flows of the Underlying Properties depend upon continuing operations in these areas. This concentration could disproportionately expose the trust’s interests to operational and regulatory risk in these areas. Due to the lack of diversification in geographic location, adverse developments in exploration and production of oil and natural gas in any of these areas of operation could have a significantly greater impact on the results of operations and cash flows of the Underlying Properties than if the operations were more diversified.

The receipt of payments by Enduro Sponsor based on the hedge contracts depends upon the financial position of the hedge contract counterparties. A default by any of the hedge contract counterparties could reduce the amount of cash available for distribution to the trust unitholders.

Payments from hedge contract counterparties to Enduro Sponsor are intended to offset costs and thus have the effect of providing additional cash to the trust during periods of lower crude oil prices. In the event that any of the counterparties to the hedge contracts default on their obligations to make payments to Enduro Sponsor under the hedge contracts, the cash distributions to the trust unitholders could be materially reduced. Enduro Sponsor does not have any security interest from its hedge counterparties against which it could recover in the event of a default by any such counterparty.

Tax Risks Related to the Trust’s Trust Units

The tax treatment of an investment in trust units could be affected by recent and potential legislative changes, possibly on a retroactive basis.

The recently enacted Health Care and Education Affordability Reconciliation Act of 2010 includes a provision that, in taxable years beginning after December 31, 2012, subjects an individual having modified adjusted gross income in excess of $200,000 (or $250,000 for married taxpayers filing joint returns) to a “Medicare tax” equal generally to 3.8% of the lesser of such excess or the individual’s net investment income, which appears to include royalty income, if any, derived from the trust units as well as any net gain from the disposition of trust units. In addition, absent new legislation

extending the current rates, beginning January 1, 2013, the highest marginal U.S. federal income tax rate applicable to ordinary income and long-term capital gains of individuals will increase to 39.6% and 20%, respectively. Moreover, these rates are subject to change by new legislation at any time.

The trust has not requested a ruling from the IRS regarding the tax treatment of the trust. If the IRS were to determine (and be sustained in that determination) that the trust is not a “grantor trust” for federal income tax purposes, the trust could be subject to more complex and costly tax reporting requirements that could reduce the amount of cash available for distribution to trust unitholders.

If the trust were not treated as a grantor trust for federal income tax purposes, the trust should be treated as a partnership for such purposes. Although the trust would not become subject to federal income taxation at the entity level as a result of treatment as a partnership, and items of income, gain, loss and deduction would flow through to the trust unitholders, the trust’s tax reporting requirements would be more complex and costly to implement and maintain, and its distributions to trust unitholders could be reduced as a result.

Neither Enduro Sponsor nor the trustee has requested a ruling from the IRS regarding the tax status of the trust, and neither Enduro Sponsor nor the trust can assure you that such a ruling would be granted if requested or that the IRS will not challenge these positions on audit.

Trust unitholders should be aware of the possible state tax implications of owning trust units. Please read “State Tax Considerations.”

Certain U.S. federal income tax preferences currently available with respect to oil and natural gas production may be eliminated as a result of future legislation.

Among the changes contained in President Obama’s Budget Proposal for Fiscal Year 2012 (the “Budget Proposal”) is the elimination of certain key U.S. federal income tax preferences relating to oil and natural gas exploration and production. The Budget Proposal proposes to eliminate certain tax preferences applicable to taxpayers engaged in the exploration or production of natural resources. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for United States production activities and (iv) the increase in the amortization period from two years to seven years for geophysical costs paid or incurred in connection with the exploration for, or development of, oil or gas within the United States. It is unclear whether any such changes will actually be enacted into law or, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals, or any other similar changes in U.S. federal income tax laws that eliminate certain tax preferences that are currently available with respect to oil and natural gas exploration and production, could reduce the cash available for distribution to the trust unitholders or adversely affect the value of the trust units.

You will be required to pay taxes on your share of the trust’s income even if you do not receive any cash distributions from the trust.

Trust unitholders are treated as if they own the trust’s assets and receive the trust’s income and are directly taxable thereon as if no trust were in existence. Because the trust will generate taxable income that could be different in amount than the cash the trust distributes, you will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of the trust’s taxable income even if you receive no cash distributions from the trust. You may not receive cash distributions from the trust equal to your share of the trust’s taxable income or even equal to the actual tax liability that results from that income.

A portion of any tax gain on the disposition of the trust units could be taxed as ordinary income.

If you sell your trust units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those trust units. A substantial portion of any gain recognized may be taxed as ordinary income due to potential recapture items, including depletion recapture. Please read “Federal Income Tax Consequences — Tax Consequences to U.S. Trust Unitholders — Disposition of Trust Units.”

The trust will allocate its items of income, gain, loss and deduction between transferors and transferees of the trust units each month based upon the ownership of the trust units on the monthly record date, instead of on the basis of the date a particular trust unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among the trust unitholders.

The trust will generally allocate its items of income, gain, loss and deduction between transferors and transferees of the trust units each month based upon the ownership of the trust units on the monthly record date, instead of on the basis of the date a particular trust unit is transferred. It is possible that the IRS could disagree with this allocation method and could assert that income and deductions of the trust should be determined and allocated on a daily or prorated basis, which could require adjustments to the tax returns of the trust unitholders affected by the issue and result in an increase in the administrative expense of the trust in subsequent periods. Please read “Federal Income Tax Consequences — U.S. Federal Income Tax Consequences — Direct Taxation of Trust Unitholders.”

FORWARD-LOOKING STATEMENTS

This prospectus contains “forward-looking statements” about Enduro Sponsor and the trust that are subject to risks and uncertainties. All statements other than statements of historical fact included in this prospectus, including, without limitation, statements under “Prospectus Summary” and “Risk Factors” regarding the financial position, business strategy, production and reserve growth and other plans and objectives for the future operations of Enduro Sponsor and the trust are forward-looking statements. Such statements may be influenced by factors that could cause actual outcomes and results to differ materially from those projected. Forward-looking statements are subject to risks and uncertainties and include statements made in this prospectus under “Projected Cash Distributions,” statements pertaining to future development activities and costs, and other statements in this prospectus that are prospective and constitute forward-looking statements.

When used in this document, the words “believes,” “expects,” “anticipates,” “intends” or similar expressions are intended to identify such forward-looking statements. The following important factors, in addition to those discussed elsewhere in this prospectus, could affect the future results of the energy industry in general, and Enduro Sponsor and the trust in particular, and could cause actual results to differ materially from those expressed in such forward-looking statements:


	•	risks associated with the drilling and operation of oil and natural gas wells;

	•	the amount of future direct operating expenses and development expenses;

	•	the effect of existing and future laws and regulatory actions;

	•	the effect of changes in commodity prices or in alternative fuel prices;


	•	the impact of hedge contracts;


	•	conditions in the capital markets;

	•	competition from others in the energy industry;

	•	uncertainty of estimates of oil and natural gas reserves and production; and

	•	cost inflation.

You should not place undue reliance on these forward-looking statements. All forward-looking statements speak only as of the date of this prospectus. Enduro Sponsor does not undertake any obligation to release publicly any revisions to the forward-looking statements to reflect events or circumstances after the date of this prospectus or to reflect the occurrence of unanticipated events, unless the securities laws require it to do so.

This prospectus describes other important factors that could cause actual results to differ materially from expectations of Enduro Sponsor and the trust, including under the heading “Risk Factors.” All written and oral forward-looking statements attributable to Enduro Sponsor, the trust, or persons acting on behalf of Enduro Sponsor or the trust are expressly qualified in their entirety by such factors.

USE OF PROCEEDS

Enduro Sponsor is offering all of the trust units to be sold in this offering, including the trust units to be sold upon the exercise of the underwriters’ option to purchase additional trust units. Enduro Sponsor expects to receive net proceeds from the sale of [ ] trust units offered by this prospectus of approximately $ million, after deducting underwriting discounts and commissions, structuring fees and offering expenses, and an additional $ million if the underwriters exercise their option to purchase additional trust units in full. Enduro Sponsor is deemed to be an underwriter with respect to the trust units offered hereby.

Enduro Sponsor intends to use the net proceeds from this offering, including any proceeds from the exercise of the underwriters’ option to purchase additional trust units, to repay borrowings outstanding under its senior secured credit agreement and for general limited liability company purposes, which may include additional acquisitions. The table below sets forth these intended uses with the corresponding dollar amounts planned for such use, assuming no exercise of the underwriters’ over-allotment option.


	Intended Amount
Intended Use	Dedicated to Such Use

Repay borrowings outstanding under senior secured credit agreement	$	million
General limited liability company purposes	$	million

On December 1, 2010 Enduro Sponsor entered into a $500 million senior secured credit agreement, which provides for revolving loans. Borrowings under the revolving credit facility have a maturity date of December 1, 2015 and bear interest at the applicable LIBOR rate, plus applicable margins ranging from 1.75% to 2.75%, or at a base rate, based upon the greatest of (a) the Prime Rate, (b) the Federal Funds Rate plus 0.5%, and (c) LIBOR plus 1%, plus applicable margins ranging from 0.75% to 1.75%.

As of June 30, 2011, total borrowings under Enduro Sponsor’s revolving credit facility were $231 million and had a weighted average interest rate of approximately 3.3% for the second quarter of 2011. The current borrowings under the revolving credit facility were incurred to fund the acquisition of the Acquired Properties.

ENDURO SPONSOR

The Underlying Properties were acquired in three separate transactions and are located in two different geographic regions: the Permian Basin and East Texas/North Louisiana. After giving pro forma effect to the conveyance of the Net Profits Interest to the trust, the offering of the trust units contemplated by this prospectus and the application of the net proceeds as described in “Use of Proceeds,” as of March 31, 2011, Enduro Sponsor would have had total assets of $610.3 million and total liabilities of $57.7 million. For an explanation of the pro forma adjustments, please read “Financial Statements of Enduro Sponsor — Unaudited Pro Forma Financial Statements — Introduction.”

The trust units do not represent interests in, or obligations of, Enduro Sponsor.

Summary Historical and Unaudited Pro Forma Financial, Operating and Reserve Data of Enduro Sponsor

The summary historical audited financial data presented below should be read in conjunction with “Information about Enduro Resource Partners LLC (Enduro Sponsor) — Selected Historical and Unaudited Pro Forma Financial, Operating and Reserve Data of Enduro Sponsor” and the accompanying financial statements and related notes of Enduro Sponsor included elsewhere in this prospectus. The summary historical audited financial data of the Predecessor as of December 31, 2009 and 2010 and for each of the years in the three-year period ended December 31, 2010 have been derived from the Predecessor’s audited financial statements. Operations of the Predecessor Properties are deemed to be the “predecessor” of Enduro Sponsor and recorded transactions are shown separately based on the ownership of the Predecessor Properties. EAC owned the Predecessor Properties prior to March 9, 2010, at which time Denbury Resources Inc. acquired the properties in connection with its acquisition of EAC. Enduro Sponsor then acquired the Predecessor Properties on December 1, 2010. Accordingly, the audited financial statements of the Predecessor as of and for the three years ended December 31, 2010 are presented for (i) “Predecessor-EAC” for the years ended December 31, 2008 and 2009 and for the period from January 1, 2010 through March 8, 2010; (ii) “Predecessor-DNR” for the period from March 9, 2010 through November 30, 2010 and (iii) “Enduro Sponsor” for the period from Enduro Sponsor’s inception (March 3, 2010) through December 31, 2010.


				Enduro
				Sponsor						Enduro
	Enduro			Pro Forma as			Enduro			Sponsor
	Sponsor			Adjusted for			Sponsor			Pro Forma as
	Pro Forma			the Offering			Pro Forma			Adjusted for
	for the			(Including the			for the			the Offering
	Acquisition			Conveyance			Acquisition			(Including the
	of the			of the			of the			Conveyance
	Acquired			Net Profits			Acquired			of the		Enduro Sponsor						Enduro Sponsor						Predecessor-EAC
	Properties			Interest)			Properties			Net Profits Interest)											Predecessor-DNR			January 1,
	Three Months			Three Months			Year			Year		Three Months			Inception			Inception			March 9, 2010			2010
	Ended			Ended			Ended			Ended		Ended			Through			Through			Through			Through
	March 31,			March 31,			December 31,			December 31,		March 31,			March 31,			December 31,			November 30,			March 8,			Year Ended December 31,
	2011			2011			2010			2010		2011			2010			2010			2010			2010			2009			2008
(In thousands)	(Unaudited)			(Unaudited)			(Unaudited)			(Unaudited)		(Unaudited)			(Unaudited)

Revenues	$	33,793		$	31,142		$	137,712		$	124,848	$	22,952		$	—		$	3,975		$	40,210		$	12,164		$	33,907		$	62,370

Net income (loss)	$	(9,559	)	$	(5,847	)	$	(8,645	)	$	6,185	$	(11,495	)	$	(77	)	$	(8,222	)	$	(19,515	)	$	(17,821	)	$	(25,853	)	$	19,540

Total assets (at period end)				$	610,335							$	735,806		$	100		$	361,832		$	397,314		$	313,106		$	301,127		$	256,783

Long-term liabilities, excluding current maturities (at period end)				$	27,392							$	260,392		$	—		$	66,211		$	587		$	1,412		$	1,404		$	1,322

Members’ equity/owners’ equity				$	552,672							$	445,143		$	23		$	273,939		$	374,731		$	290,073		$	281,439		$	234,433

The table below includes selected historical production and reserve information for Enduro Sponsor for the periods presented.


	Enduro Sponsor				Predecessor-DNR		Predecessor - EAC
	Inception		Inception		March 9, 2010		January 1
	Through		Through		Through		Through		Year Ended
	March 31,		December 31,		November 30,		March 8,		December 31,
	2010		2010		2010		2010		2009		2008
Production (MBoe)		—		143		1,505		329		1,463		1,194
Net proved reserves (MBoe) (at period end)		—		16,432		18,059		17,936		18,265		10,357
Net proved developed reserves (MBoe) (at period end)		—		10,667		9,679		8,685		9,014		7,836

Management of Enduro Sponsor

Set forth in the table below are the names, ages and titles of the managers and executive officers of Enduro Sponsor.


Name	Age	Title

Jon S. Brumley	40	President, Chief Executive Officer and Manager
John W. Arms	44	Executive Vice President, Chief Operating Officer and Manager
Kimberly A. Weimer	32	Vice President and Chief Financial Officer
Bill R. Pardue	38	Director, Engineering and Operations
David J. Grahek	57	Director, Geology
David Leuschen	60	Manager
Pierre F. Lapeyre, Jr.	48	Manager
N. John Lancaster	43	Manager
I. Jon Brumley	72	Manager

Jon S. Brumley co-founded Enduro Sponsor and has been the President and Chief Executive Officer of Enduro Sponsor and a member of Enduro Sponsor’s board of managers (the “Enduro Sponsor Board”) since March 2010. Mr. Brumley is responsible for the coordination and supervision of exploration and production and the acquisition of Enduro Sponsor’s oil and natural gas reserves. Mr. Brumley was the Chief Executive Officer of EAC from January 2006 until March 2010 when it was sold to Denbury Resources Inc., a publicly traded exploration and production company. At EAC, Mr. Brumley also served as President from August 2002 until March 2010, a director on the Board of Directors from April 1999 until May 2001 and from November 2001 until March 2010 and Executive Vice President of Business Development and Corporate Secretary from April 1998 until August 2002. Mr. Brumley also served as President and Chief Executive Officer of Encore Energy Partners GP LLC (“Encore GP LLC”), the general partner of Encore Energy Partners LP (“Encore Energy”), a publicly traded master limited partnership whose general partner was owned by EAC from February 2007 until March 2010. Prior to joining EAC, Mr. Brumley held management positions at MESA Petroleum and Pioneer Natural Resources Company. Mr. Brumley received a Bachelor of Business Administration in Marketing from the University of Texas.

John W. Arms co-founded Enduro Sponsor and has been the Executive Vice President and Chief Operating Officer of Enduro Sponsor and a member of the Enduro Sponsor Board since March 2010. Mr. Arms is responsible for the coordination and supervision of acquisitions, the engineering, enhancement and exploitation of Enduro Sponsor’s existing properties as well as the engineering analysis and evaluation of its future reserve acquisitions. Prior to joining Enduro Sponsor, Mr. Arms served as Senior Vice President of Acquisitions at EAC and Encore Energy from February 2007 until its acquisition by Denbury Resources Inc. in March 2010. At EAC, Mr. Arms also served as Vice President of Business Development of EAC from September 2001 until February 2007 and as Manager of

Acquisitions and in various other petroleum engineering positions from November 1998 until September 2001. Prior to joining EAC, Mr. Arms held various positions of responsibility at XTO Energy and ARCO Oil and Gas Company. Mr. Arms received his Bachelor of Science in Petroleum Engineering from the Colorado School of Mines.

Kimberly A. Weimer has been the Vice President and Chief Financial Officer of Enduro Sponsor since April 2010. Prior to joining Enduro Sponsor, Ms. Weimer served as the Director of Investor Relations of EAC from October 2008 until its acquisition by Denbury Resources Inc. in March 2010. From May 2007 until October 2008, she was the Senior Manager of Financial Reporting at EAC responsible for all aspects of SEC reporting for Encore Energy. During this timeframe, Encore Energy completed its initial public offering and was listed on the New York Stock Exchange, completed two follow-on equity offerings, and purchased over $500 million in assets. Prior to joining EAC in 2007, Ms. Weimer worked in public accounting, beginning her career at Arthur Andersen. Ms. Weimer received a Bachelor of Science in Accounting and Finance from Louisiana State University. She is a Certified Public Accountant.

Bill R. Pardue has been the Director, Engineering and Operations of Enduro Sponsor since May 2010. Prior to joining Enduro Sponsor, Mr. Pardue served as the Asset Manager of Encore Energy from May 2007 to May 2010. Mr. Pardue also served as the Engineering Manager for EAC from June 2005 until May 2007 in the Permian and Mid-Continent regions. At EAC, Mr. Pardue also worked in various petroleum engineering positions from November 2000 until May 2005. Prior to joining EAC, Mr. Pardue worked as a production and reservoir engineer for Meridian Oil/Burlington Resources from 1996 until 2000. Mr. Pardue received a Bachelor of Science in Petroleum Engineering from Texas Tech University and a Master of Business Administration from Texas Christian University. Mr. Pardue is also a registered professional engineer in the state of Texas.

David J. Grahek has been the Director, Geology of Enduro Sponsor since June 2010. Prior to joining Enduro Sponsor, Mr. Grahek served as Geologic Advisor of EAC from June 2005 until its acquisition by Denbury Resources, Inc. in March 2010. Prior to joining EAC, Mr. Grahek held various positions of responsibility with G&G Exploration Inc. and Union Pacific Resources Company. Mr. Grahek has over 35 years of petroleum geology experience. Mr. Grahek received his Bachelor of Science in Geology from the University of Southern Colorado and completed post graduate work at the Colorado School of Mines.

David Leuschen has been a member of the Enduro Sponsor Board since March 2010. Mr. Leuschen is a founder and Senior Managing Director of Riverstone. Prior to co-founding Riverstone, Mr. Leuschen was a Partner and Managing Director at Goldman, Sachs & Co. and founder and head of the Goldman, Sachs & Co. Global Energy & Power Group. Mr. Leuschen joined Goldman, Sachs & Co. in 1977 and became head of the Global Energy & Power Group in 1985 and a Partner in 1986. He remained with Goldman, Sachs & Co. until leaving to found Riverstone. Mr. Leuschen has served as a director of Cambridge Energy Research Associates, Cross Timbers Oil Company (predecessor to XTO Energy), J. Aron Resources, Mega Energy, Inc. and Natural Meats Montana. He currently serves on the boards of directors of Legend Natural Gas, Dynamic Industries, Dynamic Offshore Resources, Titan Operating, Northern Blizzard and Barra Energia. He is also president of Switchback Ranch LLC and has served on a number of non-profit boards of directors. Mr. Leuschen received his Bachelor of Arts from Dartmouth and his Master of Business Administration from Dartmouth’s Amos Tuck School of Business.

Pierre F. Lapeyre, Jr. has been a member of the Enduro Sponsor Board since March 2010. Mr. Lapeyre is a founder and Senior Managing Director of Riverstone. Prior to co-founding Riverstone, Mr. Lapeyre was a Managing Director at Goldman, Sachs & Co. in its Global Energy & Power Group. Mr. Lapeyre joined Goldman, Sachs & Co. in 1986 and spent his 14-year investment banking career focused on energy and power, particularly the midstream/pipeline and oil service sectors. Mr. Lapeyre’s responsibilities included client coverage and leading the execution of a wide variety of mergers and acquisitions, initial public offerings, strategic advisory and capital markets financings for clients across all sectors of the industry. Mr. Lapeyre serves on the boards of directors of Legend Natural Gas, Titan

Specialties, Dynamic Industries, Titan Operating, Three Rivers, Northern Blizzard, Dynamic Offshore Resources and Quorum Technologies. Mr. Lapeyre received his Bachelor of Science in Finance and Economics from the University of Kentucky and his Master of Business Administration from the University of North Carolina at Chapel Hill.

N. John Lancaster has been a member of the Enduro Sponsor Board since March 2010. Mr. Lancaster is a Partner and Managing Director of Riverstone. Mr. Lancaster joined Riverstone in 2000 and is responsible for the sourcing and management of investments across the energy industry, with a particular emphasis on the oilfield service and exploration and production sectors. Prior to joining Riverstone, Mr. Lancaster was a Director with The Beacon Group, LLC, a privately held firm specializing in principal investing and strategic advisory services in the energy and other industries. Mr. Lancaster began his career at Bankers Trust and later at CS First Boston, spending time as an investment banker and equity research analyst focused on the oil service and unregulated gas transmission sectors of the energy industry. Mr. Lancaster serves on the boards of directors of Cobalt International, Titan Specialties, Dynamic Industries, Dynamic Offshore Resources, Cuadrilla Resources, Hudson Products, Liberty Resources, and Barra Energia. Mr. Lancaster received his Bachelor of Business Administration from the University of Texas, where he serves on the McCombs School of Business Advisory Council, and his Master of Business Administration from Harvard Business School.

I. Jon Brumley has been a member of the Enduro Sponsor Board since March 2010. Mr. Brumley served as the Chairman of the Board of Directors of Encore GP LLC from February 2007 to March 2010. Mr. Brumley also served as the Chairman of the Board of Directors of EAC since its inception in April 1998 until March 2010, the Chief Executive Officer from its inception until December 2005 and President from its inception until August 2002. Beginning in August 1996, Mr. Brumley served as Chairman and Chief Executive Officer of MESA Petroleum until MESA’s merger in August 1997 with Parker & Parsley to form Pioneer Natural Resources Company. He served as Chairman and Chief Executive Officer of Pioneer until joining EAC in 1998. Mr. Brumley received a Bachelor of Business Administration from the University of Texas and a Master of Business Administration from the University of Pennsylvania Wharton School of Business.

Beneficial Ownership of Enduro Sponsor

The following table sets forth, as of May 31, 2011, the beneficial ownership of limited liability company interests of Enduro Sponsor held by:


	•	each person who beneficially owns 5% or more of the outstanding membership interests in Enduro Sponsor;


	•	each manager and executive officer of Enduro Sponsor; and


	•	all managers and executive officers of Enduro Sponsor as a group.

Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all membership interests of Enduro Sponsor shown as beneficially owned by them and their address is 777 Main Street, Suite 800, Fort Worth, Texas 76102.


	Percentage of
	Membership
	Interests
	Beneficially
Name of Beneficial Owner	Owned

Enduro Resource Holdings LLC		100	%
Jon S. Brumley		—
David Leuschen		—
Pierre F. Lapeyre, Jr.		—
N. John Lancaster		—
I. Jon Brumley		—
John W. Arms		—
Kimberly A. Weimer		—
Bill R. Pardue		—
David J. Grahek		—
Managers and executive officers of Enduro Sponsor as a group (9 persons)		—

Beneficial Ownership of Enduro Royalty Trust

The following table sets forth the beneficial ownership of trust units of the trust that will be outstanding after giving effect to the consummation of this offering, assuming no exercise of the underwriters’ option to purchase additional trust units, and held, directly or indirectly, by each person who will then beneficially own 5% or more of the outstanding trust units.

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

The trust will enter into a registration rights agreement with Enduro Sponsor in connection with Enduro Sponsor’s contribution to the trust of the Net Profits Interest. Under the registration rights agreement, the trust will agree, for the benefit of Enduro Sponsor and any transferee of Enduro Sponsor’s trust units, to register the trust units they hold. In connection with the preparation and filing of any registration statement, Enduro Sponsor will bear all costs and expenses incidental to any registration statement, excluding certain internal expenses of the trust, which will be borne by the trust. Any underwriting discounts and commissions will be borne by the seller of the trust units. Please read “Trust Units Eligible for Future Sale — Registration Rights.”

THE TRUST

The trust is a statutory trust created under the Delaware Statutory Trust Act on May 3, 2011. The business and affairs of the trust will be managed by The Bank of New York Mellon Trust Company, N.A., as trustee. Enduro Sponsor has no ability to manage or influence the operations of the trust. In addition, Wilmington Trust Company will act as Delaware trustee of the trust. The Delaware trustee will have only minimal rights and duties as are necessary to satisfy the requirements of the Delaware Statutory Trust Act. In connection with the completion of this offering, Enduro Sponsor will contribute the Net Profits Interest to the trust in exchange for [ ] newly issued trust units. Enduro Sponsor will make its first payment to the trust pursuant to the Net Profits Interest in October 2011, which payment may include cash that Enduro Sponsor is required to pay to the trust relating to sales of oil and natural gas production for the months of May and June 2011 and production and development expenses for the months of May and June 2011. Subsequent distributions will only cover the net profits attributable to the Net Profits Interest for one month, and, as a result, are likely to differ substantially.

The trustee can authorize the trust to borrow money to pay trust administrative or incidental expenses that exceed cash held by the trust. The trustee may authorize the trust to borrow from the trustee as a lender provided the terms of the loan are fair to the trust unitholders. The trustee may also deposit funds awaiting distribution in an account with itself, if the interest paid to the trust at least equals amounts paid by the trustee on similar deposits, and make other short-term investments with the funds distributed to the trust. The trustee has no current plans to authorize the trust to borrow money.

The trust will pay the trustee and Delaware trustee an administrative fee of $200,000 and $2,000 per year, respectively. The trust will also incur legal, accounting, tax, advisory and engineering fees, printing costs and other administrative and out-of-pocket expenses that are deducted by the trust before distributions are made to trust unitholders. The trust will also be responsible for paying other expenses incurred as a result of being a publicly traded entity, including costs associated with annual, quarterly and monthly reports to trust unitholders, tax return and Form 1099 preparation and distribution, NYSE listing fees, independent auditor fees and registrar and transfer agent fees. Total administrative expenses of the trust on an annualized basis for 2011 are initially expected to be approximately $850,000, including the administrative fees payable to the trustee and Delaware trustee.

The trust will dissolve upon the earliest to occur of the following: (1) the trust, upon the approval of the holders of at least 75% of the outstanding trust units, sells the Net Profits Interest, (2) the annual cash available for distribution to the trust is less than $2 million for each of any two consecutive years, (3) the holders of at least 75% of the outstanding trust units vote in favor of dissolution or (4) the trust is judicially dissolved.

PROJECTED CASH DISTRIBUTIONS

Immediately prior to the closing of this offering, Enduro Sponsor will create the Net Profits Interest through a conveyance to the trust of a Net Profits Interest carved from Enduro Sponsor’s interests in certain of its oil and natural gas properties located in Texas, Louisiana and New Mexico. The Net Profits Interest will entitle the trust to receive 80% of the net profits from the sale of production of oil and natural gas attributable to the Underlying Properties.

The amount of trust revenues and cash distributions to trust unitholders will depend on, among other things:


	•	oil and natural gas sales prices;

	•	the volume of oil and natural gas produced and sold attributable to the Underlying Properties;

	•	the payments made or received by Enduro Sponsor pursuant to the hedge contracts;

	•	direct operating expenses;

	•	development expenses; and

	•	administrative expenses of the trust.

The following table presents a calculation of forecasted cash distributions to holders of trust units for the twelve months ending September 30, 2012, which was prepared by Enduro Sponsor based on the assumptions that are described below and in “— Significant Assumptions Used to Prepare the Projected Cash Distributions.”

Typically, cash payment is received by Enduro Sponsor for oil production 30 to 60 days after it is produced and for natural gas production 60 to 90 days after it is produced. Given that the trust is entitled to production effective May 1, 2011 and the initial distribution will not occur until October 2011, the initial distribution in October 2011 may relate to net profits received from production from May and June of 2011. The forecasted cash distributions assume that each of the monthly distributions during the forecasted period will relate to production from a single month. To adjust for the lag between the timing of production and the timing of cash received by Enduro Sponsor and the trust, the forecasted cash distributions for the twelve months ending September 30, 2012 are based on estimated production of oil and natural gas for the twelve months ending April 30, 2012.

In the view of Enduro Sponsor’s management, the accompanying unaudited projected financial information was prepared on a reasonable basis and reflects the best currently available estimates and judgments of Enduro Sponsor related to oil and natural gas production, operating expenses and development expenses and other general and administrative expenses based on:


	•	the oil and natural gas production estimates for the twelve months ending April 30, 2012 contained in the reserve reports;


	•	estimated direct operating expenses and development expenses for the twelve months ending April 30, 2012 contained in the reserve reports;


	•	projected payments made or received pursuant to the hedge contracts for the twelve months ending April 30, 2012;


	•	estimated general and administrative expenses of $850,000 for the twelve months ending April 30, 2012; and


	•	an adjustment for the estimated production, revenue, operating expenses and development expenses (as adjusted to reflect that Enduro Sponsor has agreed to pay for $7.2 million of development expenses otherwise attributable to the trust) expected in the twelve months ending April 30, 2012 for drilling projects in the Haynesville Shale that are not included in the reserve reports.

Please read “— Significant Assumptions Used to Prepare the Projected Cash Distributions” and “Risk Factors — Prices of oil and natural gas fluctuate, and lower prices could reduce proceeds to the trust and cash distributions to trust unitholders.”

The projections and estimates and the hypothetical assumptions on which they are based are subject to significant uncertainties, many of which are beyond the control of Enduro Sponsor or the trust. Actual cash distributions to trust unitholders, therefore, could vary significantly based upon events or conditions occurring that are different from the events or conditions assumed to occur for purposes of these projections. Cash distributions to trust unitholders will be particularly sensitive to fluctuations in oil and natural gas prices. Please read “Risk Factors — Prices of oil and natural gas fluctuate, and lower prices could reduce proceeds to the trust and cash distributions to trust unitholders.” As a result of typical production declines for oil and natural gas properties, production estimates generally decrease from year to year, and the projected cash distributions shown in the table below are not necessarily indicative of distributions for future years. Please read “— Sensitivity of Projected Cash Distributions to Oil and Natural Gas Production and Prices” below, which shows projected effects on cash distributions from hypothetical changes in oil and natural gas production and prices. Because payments to the trust will be generated by depleting assets and the trust has a finite life with the production from the Underlying Properties diminishing over time, a portion of each distribution will represent, in effect, a return of your original investment. Please read “Risk Factors — The reserves attributable to the Underlying Properties are depleting assets and production from those reserves will diminish over time. Furthermore, the trust is precluded from acquiring other oil and

natural gas properties or net profits interests to replace the depleting assets and production. Therefore, proceeds to the trust and cash distributions to trust unitholders will decrease over time.”


	Projections for the
	Twelve Month Period
	Ending September 30,
Projected Cash Distributions to Trust Unitholders	2012
	(In thousands, except per unit data)

Underlying Properties sales volumes:
Oil (MBbl)⁽¹⁾		911
Natural gas (MMcf)		7,119

Total sales (MBoe)		2,097

Assumed NYMEX price⁽²⁾:
Oil (per Bbl)	$	100.00
Natural gas (per MMBtu)		4.50
Assumed realized sales price⁽³⁾:
Oil (per Bbl)	$	96.54
Natural gas (per Mcf)		4.63
Calculation of net profits:
Gross profits⁽⁴⁾:
Oil sales	$	87,940
Natural gas sales		32,979

Total	$	120,919

Costs:
Direct operating expenses:
Lease operating expenses	$	23,489
Production and other taxes		9,225
Development expenses⁽⁵⁾		14,000

Total	$	46,714

Settlement of hedge contracts⁽⁶⁾		830

Net adjustment for additional projects⁽⁷⁾		(989	)
Net profits	$	74,046

Percentage allocable to Net Profits Interest		80%

Net profits to trust from Net Profits Interest	$	59,237

Trust general and administrative expenses⁽⁸⁾	$	850

Cash available for distribution by the trust	$	58,387

Cash distribution per trust unit (assumes [ ] million units)	$	[ ]


⁽¹⁾		Sales volumes for oil include 9 MBbls of NGLs.

⁽²⁾		For a description of the effect of lower NYMEX prices on projected cash distributions, please read “— Sensitivity of Projected Cash Distributions to Oil and Natural Gas Production and Prices.”


⁽³⁾		Sales price net of forecasted gravity, quality, transportation, gathering and processing and marketing costs. For more information about the estimates and hypothetical assumptions made in preparing the table above, see “— Significant Assumptions Used to Prepare the Projected Cash Distributions.”


⁽⁴⁾		Represents “gross profits” as described in “Computation of Net Profits.”


⁽⁵⁾		Does not include development expenses related to 21 gross (2.4 net) wells associated with development drilling projects in the Haynesville Shale. Please read footnote 7.


⁽⁶⁾		Reflects net cash impact of settlements of hedge contracts relating to production. See “The Underlying Properties — Hedge Contracts.”


⁽⁷⁾		Net adjustment for additional projects reflects the expected drilling of 21 gross (2.4 net) wells in the Haynesville Shale during the forecast period associated with development drilling projects not reflected in the reserve reports but for which notifications have been received by Enduro Sponsor as of June 2011. These additional development drilling projects are expected to increase total sales volumes by 221 MBoe, total gross profits by $3.3 million and total lease operating and development expenses and production and other taxes by $4.3 million, which is expected to result in a decrease in net profits for the Underlying Properties by $989,000 and cash available for distribution to the trust by $791,000. The amount of estimated development expenses has been adjusted to reflect the agreement by Enduro Sponsor to pay for up to $9.0 million (or $7.2 million attributable to the trust’s Net Profits Interest) of the total estimated development expenses of $11.9 million related to the 21 gross (2.4 net) wells, thereby reducing the trust’s share of development expenses associated with these wells to $2.3 million. In the absence of this payment obligation by Enduro Sponsor, the cash available for distribution to the trust would be reduced by an additional $7.2 million during the forecast period. Please read “Projected Cash Distributions — Significant Assumptions Used to Prepare the Projected Cash Distributions — Net adjustment for additional projects.”


⁽⁸⁾		Total general and administrative expenses of the trust on an annualized basis for the twelve months ending April 30, 2012 are expected to be $850,000 and will include the annual fees to the trustees, accounting fees, engineering fees, legal fees, printing costs and other expenses properly chargeable to the trust.

Significant Assumptions Used to Prepare the Projected Cash Distributions

Timing of actual distributions. In preparing the projected cash distributions above and sensitivity analysis below, the revenues and expenses of the trust were calculated based on the terms of the conveyance creating the trust’s Net Profits Interest. These calculations are described under “Computation of Net Profits Interest.” It is the intent of the trust to distribute to trust unitholders proceeds received by the trust in the month after the trust receives such funds. Monthly cash distributions will be made to holders of trust units as of the applicable record date (generally the 15^th day of each calendar month) on or before the 10^th business day after the record date. Due to the amount of time it typically takes the Third Party Operators to collect payments from their customers and distribute their payments to the interest owners, including Enduro Sponsor, it has been assumed, for purposes of the projections, that cash distributions for each month will include oil production from 60 to 90 days prior to the distribution date and natural gas production from 90 to 120 days prior to the distribution date. The first distribution is expected to be made on or about October 28, 2011 to record trust unitholders as of or about October 14, 2011, and may include cash that Enduro Sponsor is required to pay to the trust relating to sales of oil and natural gas production for the months of May and June 2011 and production and development expenses for the months of April and May 2011.

Production estimates and development expenses. Production estimates for the twelve months ending April 30, 2012 are based on the reserve reports. Production from the Underlying Properties for the twelve months ending April 30, 2012 is estimated to be 911 MBbls of oil and 7,119 MMcf of natural gas. Net sales for the year ended December 31, 2010 were 939 MBbls of oil and 7,171 MMcf of natural gas. Although Enduro Sponsor expects annual production from the Underlying Properties to be shallow declining over the next five years due to development drilling by the Third Party Operators, as reflected in the reserve reports, Enduro Sponsor expects the actual annual decline rate after five years will increase to 9% per year. The expected increase in the annual decline rate is primarily a result of the assumption that no additional development drilling or other development expenditures will be made after 2015 on the Underlying Properties. Enduro Sponsor expects that the actual decline rate will be smaller over the next 20 years after 2015 if additional capital is invested.

Oil and natural gas prices. Assumed NYMEX oil and natural gas prices differ from the actual price received for production attributable to the Underlying Properties. Differentials between published oil and natural gas prices and the prices actually received for the oil and natural gas production may vary significantly due to market conditions, transportation, gathering and processing costs, quality of production and other factors.

In the above table, an average of $3.46 per Bbl is deducted from, and an average of $0.13 per Mcf is added to, the assumed NYMEX futures price for crude oil and natural gas, respectively, to reflect these differentials. These differences are based on Enduro Sponsor’s estimate of the average difference between the NYMEX published price of crude oil and natural gas and the price to be received by Enduro Sponsor for production attributable to the Underlying Properties during the twelve months ending April 30, 2012. Projected average oil and natural gas prices appearing in this prospectus have been adjusted for these differentials.

The differentials to published oil and natural gas prices applied in the above projected cash distribution estimate are based upon an analysis by Enduro Sponsor of the historic price differentials for production from the Underlying Properties with consideration given to gravity, quality and transportation and marketing costs that may affect these differentials. There is no assurance that these assumed differentials will occur.

When oil and natural gas prices decline, the operators of the properties comprising the Underlying Properties may elect to reduce or completely suspend production. No adjustments have been made to estimated production during the twelve months ending April 30, 2012 to reflect potential reductions or suspensions of production.

Settlement of Hedge Contracts. Enduro Sponsor has entered into commodity derivative contracts with unaffiliated third parties in order to mitigate the effects of falling commodity prices through 2013.

Costs. For the twelve months ending April 30, 2012, Enduro Sponsor estimates lease operating expenses to be approximately $23.4 million, production and other taxes to be approximately $9.2 million and development costs incurred to be approximately $14.0 million. For the year ended December 31, 2010, lease operating expenses of the Underlying Properties were $24.6 million, property and other taxes were $8.1 million and development costs incurred were $37.0 million. Enduro Sponsor believes drilling activity during the year ended December 31, 2010 was in excess of that which will be undertaken in each of the next five years. For a description of direct operating expenses, see “Computation of Net Profits — Net Profits Interest.”

Net adjustment for additional projects. Net adjustment for additional projects reflects the expected drilling of 21 gross (2.4 net) wells in the Haynesville Shale during the forecast period associated with development drilling projects not reflected in the reserve reports but for which notifications have been received by Enduro Sponsor as of June 2011 and as identified in the conveyance relating to the Net Profits Interest. The additional wells are expected to increase total sales volumes for the Underlying Properties during the forecast period by 221 MBoe. In estimating the production attributable to the Haynesville Shale projects discussed above, Enduro Sponsor used the same methodologies and assumptions as were used in the preparation of the reserve reports by Cawley Gillespie. During the forecast period, the additional wells are expected to increase total gross profits with respect to the Underlying Properties by approximately $3.3 million and total lease operating and development expenses and production and other taxes by $4.3 million, which is expected to result in a decrease in net profits for the Underlying Properties by $989,000 and cash available for distribution to the trust by $791,000. The amount of estimated development expenses has been adjusted to reflect the agreement by Enduro Sponsor to pay for up to $9.0 million (or $7.2 million attributable to the trust’s Net Profits Interest) of the total estimated development expenses of $11.9 million related to the 21 gross (2.4 net) wells, thereby reducing the trust’s share of development expenses associated with these wells to $2.3 million. In the absence of this payment obligation by Enduro Sponsor, the cash available for distribution to the trust would be reduced by an additional $7.2 million during the forecast

period. Enduro Sponsor will not pay the trust’s share of any development costs relating to these wells in excess of the amounts described above, so the trust will bear 80% of any incremental development expenses. Enduro Sponsor will also not pay the trust’s share of any development costs for additional wells that may be drilled during the forecast period.

General and administrative expense. The trust will be responsible for paying the annual fees to the trustees, all accounting fees, engineering fees, legal fees, printing costs and other out-of-pocket expenses incurred by or at the direction of the trustee or the Delaware trustee. The trust will also be responsible for paying other expenses incurred as a result of being a publicly traded entity, including costs associated with annual, quarterly and monthly reports to trust unitholders, tax return and Form 1099 preparation and distribution, NYSE listing fees, independent auditor fees and registrar and transfer agent fees. These general and administrative expenses are anticipated to be approximately $850,000 for the twelve months ending April 30, 2012. General and administrative expenses for subsequent years could be greater or less depending on future events that cannot be predicted. Included in the estimates is an annual administrative fee of $200,000 and $2,000 for the trustee and Delaware trustee, respectively. The trust will pay, out of the first cash payment received by the trust, the trustee’s and Delaware trustee’s legal expenses incurred in forming the trust as well as their acceptance fees in the amount of $10,000 and $1,500, respectively. These costs will be deducted by the trust before distributions are made to trust unitholders. See “The Trust.”

Sensitivity of Projected Cash Distributions to Oil and Natural Gas Production and Prices

The amount of revenues of the trust and cash distributions to the trust unitholders will be directly dependent on the sales price for oil and natural gas production sold from the Underlying Properties, the volumes of oil and natural gas produced attributable to the Underlying Properties, payments made or received under the hedge contracts and variations in direct operating expenses and development expenses.

The table and discussion below set forth sensitivity analyses of annual cash distributions per trust unit for the twelve months ending September 30, 2012, on the assumption that a trust unitholder purchased a trust unit in this offering and held such trust unit until the monthly record date for distributions for September 2012, based upon (1) the assumption that a total of [ ] trust units are issued and outstanding after the closing of the offering made hereby; (2) realization of the production levels estimated in the reserve reports; (3) the hypothetical commodity prices based upon assumed NYMEX prices; (4) the impact of the hedge contracts entered into by Enduro Sponsor that relate to production from the Underlying Properties; and (5) other assumptions described above under “— Significant Assumptions Used to Prepare the Projected Cash Distributions.” The hypothetical commodity prices of oil and natural gas production shown have been chosen solely for illustrative purposes.

The table below is not a projection or forecast of the actual or estimated results from an investment in the trust units. The purpose of the table below is to illustrate the sensitivity of cash distributions to changes in oil and natural gas pricing (giving effect to the hedge contracts that will be in place during the twelve months ending April 30, 2012). There is no assurance that the hypothetical assumptions described below will actually occur or that NYMEX futures prices will not change by amounts different from those shown in the tables.

The trust’s hedge contracts will be in effect only through December 31, 2013, and thus there is likely to be greater fluctuation in cash distributions resulting from fluctuations in the realized oil and natural gas prices in periods subsequent to the expiration of those contracts. See “Risk Factors” for a discussion of various items that could impact production levels and the prices of crude oil and natural gas.

Sensitivity of Projected Annual Cash Distribution Per Trust Unit
to Changes in NYMEX Futures Pricing

THE UNDERLYING PROPERTIES

The Underlying Properties consist of producing and non-producing interests in oil and natural gas units, wells and lands in Texas, Louisiana and New Mexico. The Underlying Properties include a portion of the assets in East Texas and North Louisiana acquired by Enduro Sponsor from Denbury Resources Inc. in December 2010, and all of the assets in the Permian Basin of New Mexico and West Texas acquired by Enduro Sponsor from Samson Investment Company and ConocoPhillips Company in January 2011 and February 2011, respectively. The Underlying Properties are divided into two geographic regions: the Permian Basin region and East Texas/North Louisiana region.

As of December 31, 2010, the Underlying Properties had proved reserves of 27.1 MMBoe. A majority of the proved reserves attributable to Underlying Properties are proved developed reserves. Proved developed reserves are the most valuable and lowest risk category of reserves because their production requires no significant future development expenses. As of December 31, 2010, approximately 75% of the volumes and 91% of the PV-10 value of the proved reserves associated with the Underlying Properties were attributed to proved developed reserves. As of December 31, 2010, the Third Party Operators and Enduro Sponsor were the operators of 99% and 1%, respectively, of the proved reserves attributable to the Underlying Properties, based on PV-10 value.

The following table sets forth, as of December 31, 2010, certain estimated proved reserves, estimated future net revenues and the discounted present value thereof attributable to the Underlying Properties, 80% of the Underlying Properties and the Net Profits Interest, in each case derived from the reserve reports.


			80% of the		Net
	Underlying		Underlying		Profits
	Properties⁽¹⁾		Properties⁽²⁾		Interest
	(In thousands)

Proved Reserves
Oil (MBbls)⁽³⁾		12,766		10,213		5,642
Natural Gas (MMcf)		85,787		68,630		43,058
Oil Equivalents (Mboe)⁽⁴⁾		27,064		21,651		12,818
Future Net Revenues	$	1,344,718	$	1,075,774	$	616,091
Future Production Cost	$	578,014	$	462,411	$	48,895	⁽⁵⁾
Future Development Cost	$	57,674	$	46,139	$	—

Future Net Income	$	709,030	$	567,196	$	567,196
Present Value at 10% Discount Rate⁽⁶⁾	$	349,532	$	279,688	$	279,688
Standardized Measure of Discounted Future Net Cash Flows	$	349,532	$	279,688	$	279,688


⁽¹⁾		Reserve volumes and estimated future net revenues for the Underlying Properties reflect volumes and revenues attributable to Enduro Sponsor’s net interests in the properties comprising the Underlying Properties.


⁽²⁾		Reflects 80% of the proved reserves and future net revenues, production and development cost, net income and present value attributable to the Underlying Properties expected to be produced based on the reserve report.

⁽³⁾		Proved reserves for oil include volumes for NGLs (MBbls) of 183 MBbls, 146 MBbls and 101 MBbls attributable to the Underlying Properties, 80% of the Underlying Properties and the Net Profits Interest, respectively.

⁽⁴⁾		The proved reserves for 80% of the Underlying Properties and the Net Profits Interest of 21,651 Mboe and 12,818 Mboe differ by 8,833 Mboe. Proceeds from the sale of the 8,833 Mboe will be used to cover 80% of the future production and development costs attributable to the Underlying Properties for the benefit of the trust.


⁽⁵⁾		Future production costs for the Net Profits Interest consist solely of severance taxes and ad valorem taxes attributable to the trust.


⁽⁶⁾		The present values of the future net revenues for the Underlying Properties and the Net Profits Interest were determined using a discount rate of 10% per annum. As of December 31, 2010, Enduro Sponsor was structured as a limited liability company. Accordingly, no provision for federal or state income taxes has been provided because taxable income was passed through to the members of Enduro Sponsor.

Average net production from the Underlying Properties for the year ended December 31, 2010 was approximately 5,847 Boe per day (or 4,678 Boe per day attributable to 80% of the Underlying Properties for the benefit of the trust), comprised of approximately 47% oil and 53% natural gas. For 2010, the oil revenues generated by the Underlying Properties was $70.0 million and natural gas revenues generated by the Underlying Properties was $33.8 million.

Enduro Sponsor’s interests in the Underlying Properties require Enduro Sponsor to bear its proportionate share of the costs of development and operation of such properties. As of December 31, 2010, Enduro Sponsor held average working interests of 19.52% and 26.16% and average net revenue interest of 16.11% and 20.00% in the Underlying Properties located in the Permian Basin and East Texas/North Louisiana regions, respectively. The Underlying Properties are also burdened by non-cost bearing interests owned by third parties consisting primarily of overriding royalty and royalty interests.

Unaudited Pro Forma Combined Financial and Operating Data of the Underlying Properties

The following table sets forth revenues, direct operating expenses and the excess of revenues over direct operating expenses relating to the Underlying Properties for the three months ended March 31, 2011 and 2010 and for the three years in the period ended December 31, 2010 derived from the unaudited pro forma combined statements of historical revenues and direct operating expenses of the Underlying Properties included elsewhere in this prospectus.


	Three Months Ended March 31				Year Ended December 31,
	2011		2010		2010		2009		2008
	(In thousands)

Revenues:
Oil	$	20,150	$	17,354	$	70,033	$	55,309	$	106,801
Natural gas		7,262		9,838		33,787		33,053		76,001

Total revenues	$	27,412	$	27,192	$	103,820	$	88,362	$	182,802

Direct operating expenses:
Lease operating	$	6,185	$	6,206	$	24,579	$	25,822	$	29,331
Gathering and processing		489		419		1,977		1,885		3,035
Production and other taxes		2,005		2,052		8,069		7,512		11,217

Total direct operating expenses	$	8,679	$	8,677	$	34,625	$	35,219	$	43,583

Excess of revenues over direct operating expenses	$	18,733	$	18,515	$	69,195	$	53,143	$	139,219

The following table provides oil and natural gas sales volumes, average sales prices, average costs per Boe and capital expenditures relating to the Underlying Properties for the three months ended March 31, 2011 and 2010 and for the three years in the period ended December 31, 2010. This operating data includes the effect of the Acquired Properties for all periods presented.


	Three Months Ended
	March 31,				Year Ended December 31
	2011		2010		2010		2009		2008
	(Unaudited)

Operating data:
Sales volumes:
Oil (MBbls)		230		239		939		1,016		1,084
Natural gas (MMcf)		1,619		1,768		7,171		8,455		8,868
Total sales (MBoe)		500		534		2,134		2,425		2,562
Average sales prices:
Oil (per Bbl)	$	87.61	$	72.61	$	74.58	$	54.44	$	98.52
Natural gas (per Mcf)		4.49		5.56		4.71		3.91		8.57
Average costs per Boe:
Lease operating	$	12.37	$	11.62	$	11.52	$	10.65	$	11.45
Gathering and processing		0.98		0.79		0.93		0.78		1.18
Production and other taxes		4.01		3.58		3.78		3.10		4.38
Capital expenditures (in thousands):
Property development costs	$	12,105	$	1,781	$	37,036	$	18,532	$	65,571

Discussion and Analysis of Pro Forma Combined Historical Results of the Underlying Properties

Comparison of Pro Forma Combined Historical Results for the Three Months Ended March 31, 2011 and 2010

Excess of revenues over direct operating expenses for the Underlying Properties increased by $0.2 million to $18.7 million for the three months ended March 31, 2011 as a result of a $0.2 million increase in revenues.

Revenues. Revenues from oil and natural gas sales increased $0.2 million between the periods. This increase in revenues was primarily the result of an increase in the average price received for crude oil sold from $72.61 per Bbl for the three months ended March 31, 2010 to $87.61 per Bbl for the three months ended March 31, 2011, partially offset by a 0.1 MBbl decrease in oil volumes sold.

Lease operating expenses. Lease operating expenses remained relatively constant at $6.2 million for the three months ended March 31, 2011 and March 31, 2010.

Gathering and processing expenses. Gathering and processing expenses increased by $0.1 million from $0.4 million for the quarter ended March 31, 2010 to $0.5 million for the quarter ended March 31, 2011.

Production and other taxes. Production and other taxes decreased $0.1 million as a result of the decrease in oil and natural gas volumes sold on which production taxes are based.

Comparison of Pro Forma Combined Historical Results for the Years Ended December 31, 2010 and 2009

Excess of revenues over direct operating expenses for the Underlying Properties was $69.2 million for the year ended December 31, 2010, compared to $53.1 million for the year ended December 31, 2009. The increase was primarily a result of an increase in the average price received for the oil and natural gas sold. This was partially offset by a decrease in production.

Revenues. Revenues from oil and natural gas sales increased $15.5 million between the periods. This increase in revenues was primarily the result of an increase in the average price received for crude oil sold from $54.44 per Bbl for the year ended December 31, 2009 to $74.58 per Bbl for the year ended December 31, 2010, partially offset by a 77 MBbl decrease in oil volumes sold. The increase in revenues was also the result of an increase in the average price received for natural gas sold from $3.91 per Mcf for the year ended December 31, 2009 to $4.71 per Mcf for the year ended December 31, 2010, partially offset by a 1,284 MMcf decrease in natural gas volumes sold.

Lease operating expenses. Lease operating expenses decreased to $24.6 million for the year ended December 31, 2010 from $25.8 million for the year ended December 31, 2009, primarily due to a decrease in volumes partially offset by an $0.87 per Boe increase in lease operating expense rate.

Gathering and processing expenses. Gathering and processing expenses remained essentially stable increasing by $0.1 million to $2.0 million for the year ended December 31, 2010.

Production and other taxes. Production and other taxes increased $0.6 million as a result of the increase in revenues from oil and natural gas sales on which these taxes are based.

Comparison of Pro Forma Combined Historical Results for the Years Ended December 31, 2009 and 2008

The pro forma combined historical results for the year ended December 31, 2008 were derived from the unaudited statements of revenues and direct operating expenses of the Predecessor Underlying Properties, the Samson Permian Basin Assets and the ConocoPhillips Permian Basin Assets, in each case for the year ended December 31, 2008, which are included in this prospectus on pages F-5, F-14 and F-22, respectively.

Excess of revenues over direct operating expenses for the Underlying Properties was $53.1 million for the year ended December 31, 2009, compared to $139.2 million for the year ended December 31, 2008. The decrease was primarily a result of a decrease in the average price received for the oil and natural gas sold.

Revenues. Revenues from oil and natural gas sales decreased $94.4 million between these periods. This decrease in revenues was primarily the result of a decrease in the average price received for crude oil sold from $98.52 per Bbl for the year ended December 31, 2008 to $54.44 per Bbl for the year ended December 31, 2009, and a 68 MBbl decrease in oil volumes sold. The decrease in revenues was also the result of a decrease in the average price received for natural gas sold from $8.57 per Mcf for the year ended December 31, 2008 to $3.91 per Mcf for the year ended December 31, 2009, and a 413 MMcf decrease in natural gas volumes sold.

Lease operating expenses. Lease operating expenses decreased from $29.3 million for the year ended December 31, 2008 to $25.8 million for the year ended December 31, 2009. This decrease was primarily a result of a decrease in volumes.

Gathering and processing expenses. Gathering and processing expenses decreased $1.1 million from $3.0 million for the year ended December 31, 2008 to $1.9 million for the same period in 2009 due to lower volumes coupled with a lower processing fee per Mcf.

Production and other taxes. Production and other taxes decreased $3.7 million as a result of the decreases in the price of crude oil and in revenues from oil and natural gas sales, on which these taxes are based.

Hedge Contracts

The revenues derived from the Underlying Properties depend substantially on prevailing oil prices and, to a lesser extent, natural gas prices. As a result, commodity prices also affect the amount of cash flow available for distribution to the trust unitholders. Lower prices may also reduce the amount of oil and natural gas that the Third Party Operators or Enduro Sponsor can economically

produce. Enduro Sponsor has entered into hedge contracts to reduce the exposure of the revenues from oil and natural gas production from the Underlying Properties to fluctuations in oil and natural gas prices and to achieve more predictable cash flow. However, these contracts limit the amount of cash available for distribution if prices increase above the fixed hedge price. The hedge contracts consist of commodity derivative contracts with unaffiliated third parties in order to mitigate the effects of falling commodity prices through 2013.

The following table sets forth the volumes involved in Enduro Sponsor’s natural gas commodity derivative contracts and the weighted-average contractual prices per Mcf as of June 30, 2011:


	Daily Put		Average		Daily Swap		Average
Period	Volumes		Price		Volumes		Price
	(Mcf)		($/Mcf)		(Mcf)		($/Mcf)

April 2011 — December 2011		14,000	$	4.20		10,000	$	4.30
January 2012 — December 2012		14,000	$	4.90		10,000	$	4.57
January 2013 — December 2013		12,000	$	4.90		8,000	$	5.00

The following table sets forth the volumes involved in Enduro Sponsor’s oil commodity derivative contracts and the weighted-average NYMEX prices per Bbl as of June 30, 2011:


	Daily		Average				Average		Average		Average		Daily
	Put		Put		Daily		Sub-Floor		Floor		Cap		Swap		Average
	Volumes		Price		Volumes		Price		Price		Price		Volumes		Price
Period	(Bbls)		($/Bbl)		(Bbls)		($/Bbl)		($/Bbl)		($/Bbl)		(Bbls)		($/Bbl)

2011		500	$	92.00		500	$	67.50	$	90.00	$	110.00		530	$	102.96
2012		500	$	92.00		500	$	67.50	$	90.00	$	110.00		520	$	104.10
2013		—	$	—		500	$	67.50	$	90.00	$	110.00		510	$	102.97

The amounts received by Enduro Sponsor from the hedge contract counterparty upon settlement of the hedge contracts will reduce the operating expenses related to the Underlying Properties in calculating net profits. In addition, the aggregate amounts paid by Enduro Sponsor on settlement of the hedge contracts will reduce the amount of net profits paid to the trust. See “Computation of Net Profits — Net Profits Interest.”

Producing Acreage and Well Counts

For the following data, “gross” refers to the total number of wells or acres in which Enduro Sponsor owns a working interest and “net” refers to gross wells or acres multiplied by the percentage working interest owned by Enduro Sponsor. All of the acreage comprising the Underlying Properties is held by production. Although many of Enduro Sponsor’s wells produce both oil and natural gas, a well is categorized as an oil well or a natural gas well based upon the ratio of oil to natural gas production. The Underlying Properties are interests in properties located in the Permian Basin of West Texas and New Mexico and in the East Texas/North Louisiana region. The following is a summary of the approximate acreage of the Underlying Properties at December 31, 2010.


	Acres
	Gross		Net

Permian Basin		278,612		30,350
East Texas/North Louisiana		15,440		4,113

Total		294,052		34,463

The following is a summary of the producing wells on the Underlying Properties as of December 31, 2010:


	Oil				Natural Gas
	Gross Wells⁽¹⁾		Net Wells		Gross Wells⁽¹⁾		Net Wells

Permian Basin		4,161		753.5		130		23.5
East Texas/North Louisiana		—		—		385		100.7

Total		4,161		753.5		515		124.2


⁽¹⁾		Enduro Sponsor’s total wells include 34 operated wells and 4,642 non-operated wells. At December 31, 2010, 64 of Enduro Sponsor’s wells had multiple completions.

The following is a summary of the number of development and exploratory wells drilled on the Underlying Properties during the last three years.


	Year Ended December 31,
	2010				2009				2008
	Gross		Net		Gross		Net		Gross		Net

Development Wells:
Productive		39		6.2		20		1.3		116		24.3
Dry holes		—		—		—		—		—		—

		39		6.2		20		1.3		116		24.3

Exploratory Wells:
Productive		13		4.7		23		7.6		22		7.3
Dry holes		—		—		3		0.6		—		—

		13		4.7		26		8.2		22		7.3

Total:
Productive		52		10.9		43		8.9		138		31.6
Dry holes		—		—		3		0.6		—		—

Total		52		10.9		46		9.5		138		31.6

Operating Areas

The following table summarizes the estimated proved reserves by operating area attributable to the Underlying Properties according to the reserve reports and the corresponding pre-tax PV-10 value as of December 31, 2010.


		Proved Reserves⁽¹⁾
													% of
				Natural				% of			PV-10		Total
	Producing	Oil		Gas		Total		Total			Value⁽²⁾		PV-10
Operating Area	Formation	(MBbls)		(MMcf)		(MBoe)		Reserves			(In thousands)		Value

Permian Basin
North Monument
Grayburg Unit	Grayburg/San Andres		2,028		1,471		2,273		15	%	$	42,989		15	%
North Central Levelland Unit	San Andres		2,330		265		2,374		14	%	$	39,208		14	%
North Cowden Unit	Grayburg/San Andres		2,403		993		2,569		16	%	$	32,563		12	%
Yates Field Unit	Grayburg/San Andres		633		—		633		4	%	$	18,052		6	%
Other	Various		5,347		18,752		8,472		51	%	$	147,163		53	%

Permian Basin Total			12,741		21,481		16,321		100	%	$	279,975		100	%


		Proved Reserves⁽¹⁾
													% of
				Natural				% of			PV-10		Total
	Producing	Oil		Gas		Total		Total			Value⁽²⁾		PV-10
Operating Area	Formation	(MBbls)		(MMcf)		(MBoe)		Reserves			(In thousands)		Value

East Texas/North Louisiana
Elm Grove Field	Cotton Valley, Hosston, Travis Peak, Haynesville Shale		2		55,442		9,238		86	%	$	54,591		79	%
Kingston Field	Travis Peak, Haynesville Shale		—		6,570		1,100		10	%	$	10,027		14	%
Stockman Field	Travis Peak		23		2,294		405		4	%	$	4,939		7	%

East Texas/North Louisiana
Total			25		64,306		10,743		100	%	$	69,557		100	%

Total			12,766		85,787		27,064		100	%	$	349,532		100	%


⁽¹⁾		In accordance with the rules and regulations promulgated by the SEC, the proved reserves presented above were determined using the twelve month unweighted arithmetic average of the first-day-of-the-month price for the period from January 1, 2010 through December 1, 2010, without giving effect to any hedge transactions, and were held constant for the life of the properties. This yielded a price for oil of $79.43 per Bbl and a price for natural gas of $4.37 per MMBtu.

⁽²⁾		PV-10 is the present value of estimated future net revenue to be generated from the production of proved reserves, discounted using an annual discount rate of 10%, calculated without deducting future income taxes and future abandonment costs. Standardized measure of discounted future net cash flows is calculated the same as PV-10 except that it deducts future income taxes and future abandonment costs. Because the trust bears no federal tax expense and taxable income is passed through to the unitholders of the trust, no provision for federal or state income taxes is included in the summary reserve reports. PV-10 may not be considered a GAAP financial measure as defined by the SEC and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. The pre-tax PV-10 value and the standardized measure of discounted future net cash flows do not purport to present the fair value of the oil and natural gas reserves attributable to Underlying Properties.

Substantially all of the Underlying Properties are located in mature oil fields that are characterized by long production histories and additional development opportunities, which may help to diminish natural declines in production from the Underlying Properties. Based on the reserve reports, approximately 47% of the future production from the Underlying Properties is expected to be oil and approximately 53% is expected to be natural gas.

Oil Recovery Overview

When an oil field is first produced, the oil typically is recovered as a result of natural pressure within the producing formation, often assisted by pumps of various types. The only natural force present to move the crude oil to the wellbore is the pressure differential between the higher pressure in the formation and the lower pressure in the wellbore. At the same time, there are many factors that act to impede the flow of crude oil, depending on the nature of the formation and fluid properties, such as pressure, permeability, viscosity and water saturation. This stage of production, referred to as “primary production,” recovers only a small fraction of the crude oil originally in place in a producing formation.

Many, but not all, oil fields are amenable to assistance from a waterflood, a form of “secondary recovery,” which is used to maintain reservoir pressure and to help sweep oil to the wellbore. In a waterflood, certain wells are used to inject water into the reservoir while other wells are

used to produce the fluid. As the waterflood matures, the fluid produced contains increasing amounts of water and decreasing amounts of oil. Surface equipment is used to separate the oil from the water, with the oil going to pipelines or holding tanks for sale and the water being recycled to the injection facilities. Primary recovery followed by secondary recovery usually produces between 20% and 40% of the crude oil originally in place in a producing formation.

A third stage of oil recovery is called “tertiary recovery” or “enhanced oil recovery” (“EOR”). In addition to maintaining reservoir pressure, this type of recovery seeks to alter the properties of the oil in ways that facilitate production. A commonly utilized method of tertiary recovery involves the use of a CO₂ flood, where CO₂ is liquefied under high pressure and injected into the reservoir. The CO₂ then swells the oil in a way that increases the mobilization of by-passed oil while also reducing the oil’s viscosity. The lighter oil fractions vaporize into the CO₂ while the CO₂ also condenses into the reservoir’s oil. In this manner, the two fluids become miscible, mixing to form a homogeneous fluid that is mobile and has lower viscosity and lower interfacial tension. The implementation of a CO₂ flood can result in increased production growth and recovery over and above that which is produced through primary and secondary recovery methods.

Permian Basin Region

The Permian Basin is one of the largest and most prolific oil and natural gas producing basins in the United States. The Permian Basin extends over 100,000 square miles in West Texas and southeast New Mexico and has produced over 24 billion Bbls of oil since its discovery in 1921. The Permian Basin is characterized by oil and natural gas fields with long production histories and multiple producing formations. The Underlying Properties in the Permian Basin contain 278,612 gross (30,350 net) acres in Texas and New Mexico. Approximately, 62% of the oil produced in the Underlying Properties in the Permian Basin comes from waterflooding and CO₂ flooding.

Four of the largest fields in the Permian Basin region of the Underlying Properties are the following (measured by PV-10 value):


	•	The largest field in the Permian Basin region is the Apache operated North Monument Grayburg Unit discovered in 1929. This unit produces 325 Boe per day net to Enduro Sponsor’s interest from the Grayburg and San Andres formations of which 90% is oil. Proved reserves attributable to the Underlying Properties in the North Monument Grayburg Unit are 2.3 MMBoe as of December 31, 2010.


	•	The second largest field in the Permian Basin region is the Apache operated North Central Levelland Unit discovered in 1937. This unit produces from the San Andres formation at a depth of approximately 4,900 feet. The North Central Levelland Unit is a waterflood property and produces 365 Boe per day net to Enduro Sponsor’s interest of which 98% is oil. Proved reserves attributable to the Underlying Properties in the North Central Levelland Unit are 2.4 MMBoe as of December 31, 2010.


	•	The third largest field in the Permian Basin region is the North Cowden Unit discovered in 1930. The North Cowden Unit is undergoing both waterflood and CO₂ recovery processes. The field produces 490 Boe per day net to Enduro Sponsor’s interest of which 94% is oil. This production is produced from the Grayburg formation at a depth of 4,500 feet. Proved reserves attributable to the Underlying Properties in the North Cowden field are 2.6 MMBoe as of December 31, 2010. The operator of the North Cowden field is Occidental, the largest oil and gas operator in the Permian Basin.


	•	The fourth largest field in the Permian Basin region is the Yates Field discovered in 1926. Kinder Morgan is the operator of the field and is producing oil through the implementation of both waterflood and CO₂ processes. The Yates Field produced 165 Boe per day net to Enduro Sponsor’s interest of which 100% is oil. Proved reserves


		attributable to the Underlying Properties in the Yates Field are 633 MBoe as of December 31, 2010.

The following table sets forth the recovery method and certain additional information about some of the fields in the Permian Basin region:


							Original
							Oil in			Cumulative
		Recovery	Working		Net Revenue		Place			Production		PV-10
Unit Name	Operator	Method	Interest (%)		Interest (%)		(MMBO)⁽¹⁾			(MMBO)		(Millions)

North Monument Grayburg Unit	Apache	Waterflood		11.2		9.9		580	⁽²⁾		152	$	43
North Central Levelland Unit	Apache	Waterflood		30.9		23.3		142	⁽³⁾		56	$	39
North Cowden Unit	Occidental	Waterflood/CO₂		8.5		7.6		1,266	⁽⁴⁾		270	$	33
Yates Field Unit	Kinder Morgan	Waterflood/CO₂		0.8		0.7		4,000	⁽⁵⁾		1,235	$	18
South Foster Unit	Occidental	Waterflood		12.7		11.1		163	⁽⁶⁾		45	$	10
Eunice Monument South Unit A	XTO	Waterflood		9.4		8.1		672	⁽⁷⁾		110	$	7
Jo-Mill Unit	Chevron	Waterflood		1.2		1.1		326	⁽⁸⁾		76	$	4
West Spraberry Unit	Chevron	Waterflood		22.7		19.7		60	⁽⁹⁾		14	$	4
Spraberry Driver Unit	Pioneer	Waterflood		1.0		0.8		600	⁽¹⁰⁾		88	$	3
Eunice Monument South Unit B	XTO	Waterflood		14.1		11.7		136	⁽¹¹⁾		22	$	3
Corrigan Cowden Unit	Occidental	Waterflood		12.2		10.7		44	⁽¹²⁾		18	$	2


⁽¹⁾		Original oil in place is not an indication of the quantity of oil that is likely to be produced, but rather an indication of the estimated size of a reservoir.

⁽²⁾		New Mexico Oil Conservation Division Case No: 10253 Navigational Message Generation Unit Application Hearing dated April 4, 1991 filed by Amerada Hess Corporation as operator.

⁽³⁾		Texas Railroad Commission April 20, 2001 Form H-1 filing by Mobil Producing TX & NM Inc. as operator.

⁽⁴⁾		Texas Railroad Commission January 16, 2001 Form H-1 filing by Occidental Permian Ltd as operator.

⁽⁵⁾		Texas Railroad Commission December 30, 1999 Form H-1 filing by Marathon Oil Company as operator.

⁽⁶⁾		Texas Railroad Commission September 11, 2001 Form H-1 filing by Occidental Permian Ltd as operator.

⁽⁷⁾		New Mexico Oil Conservation Division April, 1983 Technical Committee Report for Unitization filing by the Eunice Monument South Unit Working Interest owners.

⁽⁸⁾		Texas Railroad Commission September 18, 1968 Form H-1 filing by Texaco Inc. as operator.

⁽⁹⁾		Texas Railroad Commission April 21, 2000 Form H-1 filing by Texaco E&P Inc. as operator.

⁽¹⁰⁾		Texas Railroad Commission February 24, 1993 Form H-1 filing by Texaco E&P Inc. as operator.

⁽¹¹⁾		New Mexico Oil Conservation Division April, 1983 Technical Committee Report for Unitization filing by the Eunice Monument South Unit Working Interest owners.

⁽¹²⁾		Texas Railroad Commission June 4, 1990 Form H-1 filing by ARCO Oil and Gas Company as operator.

Enduro Sponsor owns a working interest in the above fields. Each field was identified in a 2006 study by the United States Department of Energy as having a favorable reservoir for potential CO₂ upside recovery based on reservoir depth, oil gravity, reservoir pressure, reservoir temperature and oil composition. Enduro Sponsor will not be able to influence development activities in the non-operated fields, and no assurance can be given that CO₂ flooding will commence at any time in the future or will continue to be used on any of the above fields.

East Texas/North Louisiana Region

Historically, much of the East Texas/North Louisiana region was directed at the James Lime, Pettet, Travis Peak and Cotton Valley formations. Beginning in 2008, companies in the region began to focus on the development of the Haynesville Shale utilizing horizontal drilling technology and multi-stage hydraulic fracturing well completion techniques. According to the Energy Information Administration, in 2011 the Haynesville Shale became the leading shale play in the United States by production volume. In 2010, operators began experimenting with down-spacing to 80-acre well spacing in parts of the Haynesville Shale from 160-acre well spacing, with a goal of increased overall gas recovery from the shale. Operators have also begun to focus on the efficiencies, such as drilling multiple wells from a single condensed pad location, reducing drilling times, combining fracture stimulation activities and designing facilities to be shared, in an effort to streamline operations and cut costs. Current activity on Enduro Sponsor’s acreage is focused on the horizontal development of the Haynesville Shale and Cotton Valley sands. In addition, operators in the region are beginning to test additional formations in the area such as the Bossier, Cotton Valley Lime and Smackover formations.

The Underlying Properties contain interests in 15,440 gross (4,113 net) acres in this region across three fields: the Elm Grove Field, operated by Petrohawk, the Kingston Field, operated by EXCO Resources, Inc., and the Stockman Field, operated by Enduro Sponsor. In the Kingston Field, EXCO Resources is drilling wells on 80-acre well spacing. Based on continued 80-acre well spacing, Enduro Sponsor believes the Underlying Properties may support additional Haynesville Shale wells. The proved reserves associated with the Underlying Properties in the East Texas/North Louisiana region do not include reserves attributable to 80-acre well spacing nor are there any reserves from the Bossier, Cotton Valley Lime or Smackover formations. However, the Underlying Properties include the economic rights to production from these formations on Enduro Sponsor’s acreage position in the event that production is generated from them. Enduro Sponsor will not be able to influence development activities in the non-operated fields, and no assurance can be given that such down spacing will continue or that the referenced additional formations will be produced.

Near Term Development Activities

Payment of Operating and Development Expenses

The Third Party Operators and, with respect to the Stockman Field, Enduro Sponsor, are entitled to make all determinations related to development and operating expenses with respect to the Underlying Properties, and there are no limitations on the amount of development or operating expenses that the Third Party Operators and Enduro Sponsor may incur with respect to the Underlying Properties. The trust is not directly obligated to pay any portion of any operating and development expenses made with respect to the Underlying Properties; however, operating and development expenses made by Enduro Sponsor with respect to the Underlying Properties will be included among the costs that will be deducted from the gross profits in calculating cash distributions attributable to the Net Profits Interest. As a result, the trust will indirectly bear an 80% share of any operating and development expenses made with respect to the Underlying Properties. Accordingly, higher or lower operating and development expenses will, in general, directly decrease or increase, respectively, the cash received by the trust. Please read “Computation of Net Profits — Net Profits Interest.”

2011 Capital Budget

Historical Activity. Enduro Sponsor has estimated the development of the proved undeveloped reserves attributable to the Underlying Properties based on historical activity and known current development plans of the Third Party Operators. In 2008, 2009 and 2010, 138 gross (31.6 net) wells, 46 gross (9.5 net) wells, and 52 gross (10.9 net) wells, respectively, were drilled on the Underlying Properties. In 2011, 47 gross (15.3 net) wells have been drilled or proposed and approved for drilling by Enduro Sponsor as of June 2011. Enduro Sponsor has a good working relationship with its Third Party Operators and has discussed future drilling and development plans with them.

East Texas/North Louisiana Region. For 2011, Enduro Sponsor has a capital budget of $30 million for the East Texas/North Louisiana region. Enduro Sponsor has spent $4 million of this on proved undeveloped projects and $11.3 million on non-proven probable projects and has dedicated $14.7 million to approved future projects not represented in the proved reserves. Enduro Sponsor has agreed to pay up to $9.0 million of development expenses in 2011 that occur after May 1, 2011 with respect to specified projects, which is included in Enduro Sponsor’s $30 million capital budget for 2011.

In 2011, much of the drilling activity in the East Texas/North Louisiana region has been associated with the Haynesville Shale formation, with 26 gross (5.7 net) wells having been drilled, spud, or proposed and approved. In the East Texas/North Louisiana region, Enduro Sponsor has been notified by the largest Third Party Operators of the Underlying Properties, EXCO Resources Inc. and Petrohawk, of plans to continue development in the Haynesville Shale and Lower Cotton Valley in the near term. EXCO is currently proposing 6 to 8 wells per section in the Haynesville Shale and plans to drill the wells at one time. These wells are being prepared on 80-acre spacing. The Haynesville Shale development is a fast moving immature play with much of the drilling considered to be new and extensional. As a result, the activity does not conform to the standard for proved reserves and does not appear in the reserve report relating to the Underlying Properties. Based on the level of activity in these areas and the current natural gas price environment, Enduro Sponsor believes that it is able to reasonably estimate the level of drilling activity in the near future. Enduro Sponsor expects the Third Party Operators to drill 4 proved undeveloped wells in 2011.

In the East Texas/North Louisiana region, of the 26 wells proposed to be drilled during 2011, a total of 5 wells have been drilled to date, but only 4 wells were scheduled as proved undeveloped locations in the reserve report relating to the Underlying Properties. There have been an additional 21 wells spud or proposed and approved by Enduro Sponsor in 2011 that are not represented in the reserve report because they would not be classified as proved locations but would rather be classified as probable locations based on the information available on December 31, 2010. These additional 21 wells would not be classified as proved because of one or more of the following reasons: (1) the drilling locations are more than one or two locations away from a producing well, (2) the drilling is occurring on smaller spacing than has historically occurred in the relevant field to be considered proven or (3) the wells are being drilled simultaneously in clusters of 6 or 8 wells where evidence of individual well commerciality cannot be determined. Enduro Sponsor has budgeted for this level of activity, which may have a positive impact on the proved reserves and production volumes in the future.

Permian Basin Region. For 2011, Enduro Sponsor has a capital budget of $12 million for the Permian Basin region, of which $4 million has been spent on proved undeveloped projects and $5.5 million has been dedicated to approved future projects not represented in the proved reserves. The remaining $2.5 million has been budgeted for non-proven wells and unknown projects.

In the Permian Basin region, 8 gross (4 net) wells are in the process of being drilled in the Lost Tank field operated by Occidental Petroleum in 2011. An additional 11 gross (5.5 net) wells have been spud or proposed and approved in 2011 in the Lost Tank field. Because these 11 wells are more than one location away from a producing well they are not classified as proved locations and are therefore not in the reserve report. Occidental Petroleum has stated that they will not repeat this level of activity in the Lost Tank field after 2011. For 2011, all 8 of the proved undeveloped locations in the Lost Tank field in the reserve report have been drilled. Enduro Sponsor has not scheduled any additional proved undeveloped projects for the Permian Basin region in the reserve report after 2011.

2012 Capital Budget

Enduro Sponsor’s capital budget for the Underlying Properties in 2012 is estimated to be $19.6 million, of which $17.8 million is expected to be invested in the East Texas/North Louisiana region and $1.8 million is expected to be invested in the Permian Basin. These projects could maintain or increase future distributions to the trust unitholders.

In the East Texas/North Louisiana region, Enduro Sponsor’s capital budget is expected to be $17.8 million in 2012. Investments in this region will mainly flow into Haynesville Shale drilling projects in Caddo and De Soto Parishes in Louisiana. Enduro Sponsor’s acreage in the Haynesville Shale area has significant upside potential. Over 90% of the 640 acre sections owned by Enduro Sponsor have only one producing well, which leaves 7 additional locations per section (assuming 80-acre spacing) to drive growth in this area for years to come.

In the Permian Basin, Enduro Sponsor’s capital budget is expected to be $1.8 million in 2012, including the North Cowden CO₂ projects. Past projects have typically targeted the Wolfcamp, Wolfberry, Cherry Canyon and San Andres zones. Enduro Sponsor also owns an interest in other prospective CO₂ units in the Permian Basin, with neighboring units being successfully flooded or expanded into units owned by Enduro Sponsor. The operators of these producing units have extensive experience in implementing CO₂ floods, which increase production.

Other

Any additional incremental revenue received by Enduro Sponsor from additional production resulting from future capital expenditures could have the effect of increasing future distributions to the trust unitholders. No assurance can be given, however, that any development well will produce in commercial quantities or that the characteristics of any development well will match the characteristics of the Third Party Operators’ or Enduro Sponsor’s existing wells or historical drilling success rate.

Reserve Reports

Technologies. The reserve reports were prepared using production performance decline curve analyses to determine the reserves of the Underlying Properties in Texas, Louisiana and New Mexico. After estimating the reserves of each proved developed property, it was determined that a reasonable level of certainty exists with respect to the reserves which can be expected from any individual undeveloped well in the field. The consistency of reserves attributable to the proved developed wells in Texas, Louisiana and New Mexico, which cover a wide area, further supports proved undeveloped classification.

The proved undeveloped locations in the Underlying Properties are direct offsets of other producing wells. Data from both Enduro Sponsor and offset operators with which Enduro Sponsor has exchanged technical data demonstrate a consistency in this resource play over an area much larger than the Underlying Properties. In addition, information from other producing wells has also been used to analyze reservoir properties such as porosity, thickness and stratigraphic conformity.

Internal controls. Cawley Gillespie, the independent petroleum engineering consultant, estimated all of the proved reserve information for the Underlying Properties in this registration statement in accordance with appropriate engineering, geologic and evaluation principles and techniques that are in accordance with practices generally accepted in the petroleum industry, and definitions and guidelines established by the SEC. These reserves estimation methods and techniques are widely taught in university petroleum curricula and throughout the industry’s ongoing training programs. Although these engineering, geologic and evaluation principles and techniques are based upon established scientific concepts, the application of such principles and techniques involves extensive judgment and is subject to changes in existing knowledge and technology, economic conditions and applicable statutory and regulatory provisions. These same industry-wide applied techniques are used in determining estimated reserve quantities. The technical person primarily responsible for overseeing preparation of the reserves estimates and the third party reserve reports is John W. Arms, Enduro Sponsor’s Executive Vice President and Chief Operating Officer. Mr. Arms received a Bachelor of Science in Petroleum Engineering from the Colorado School of Mines in 1991. Prior to co-founding Enduro Sponsor, Mr. Arms was Senior Vice President of Acquisitions for EAC. Mr. Arms has over 20 years of experience working in various capacities in the energy industry, including acquisition analysis, reserve estimation, reservoir engineering and operations engineering. Mr. Arms consults regularly with Cawley Gillespie during the reserve estimation process to

review properties, assumptions and relevant data. Additionally, Enduro Sponsor’s senior management has reviewed and approved all Cawley Gillespie summary reserve reports contained in this prospectus.

The independent petroleum engineer’s report as to the proved oil and natural gas reserves as of December 31, 2010 were prepared by Cawley Gillespie. Cawley Gillespie, whose firm registration number is F-693, was founded in 1961 and is a leader in the evaluation of oil and gas properties. The technical person at Cawley Gillespie primarily responsible for overseeing the reserve estimate with respect to Enduro Sponsor, the Underlying Properties and the Net Profits Interest attributable to the trust is Robert D. Ravnaas. Mr. Ravnaas has been a petroleum consultant for Cawley Gillespie since 1983, and became Executive Vice President in 1999. He is a registered professional engineer in the State of Texas (license no. 61304) and a graduate of the University of Texas with an M.S. in Petroleum Engineering. In addition, Mr. Ravnaas received a B.Sc. with special honors in Chemical Engineering from the University of Colorado.

Cawley Gillespie estimated oil and natural gas reserves attributable to Enduro Sponsor, the Underlying Properties and the Net Profits Interest as of December 31, 2010. Numerous uncertainties are inherent in estimating reserve volumes and values, and the estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of the reserves may vary significantly from the original estimates.

The discounted estimated future net revenues presented below were prepared using the twelve month unweighted arithmetic average of the first-day-of-the-month price for the period from January 1, 2010 through December 1, 2010, without giving effect to any hedge transactions, and were held constant for the life of the properties. This yielded a price for oil of $79.43 per barrel and a price for natural gas of $4.37 per MMBtu. Oil equivalents in the table are the sum of the Bbls of oil and the Boe of the stated Mcfs of natural gas, calculated on the basis that six Mcfs of natural gas is the energy equivalent of one Bbl of oil. The estimated future net revenues attributable to the Net Profits Interest as of December 31, 2010 are net of the trust’s proportionate share of all estimated costs deducted from revenue pursuant to the terms of the conveyance creating the Net Profits Interest. Because oil and natural gas prices are influenced by many factors, use of the twelve month unweighted arithmetic average of the first-day-of-the-month price for the period from January 1, 2010 through December 1, 2010, as required by the SEC, may not be the most accurate basis for estimating future revenues of reserve data. Future net cash flows are discounted at an annual rate of 10%. There is no provision for federal income taxes with respect to the future net cash flows attributable to the Underlying Properties or the Net Profits Interest because future net revenues are not subject to taxation at the Enduro Sponsor or trust level.

Proved reserves of Underlying Properties. The following table sets forth, as of December 31, 2010, certain estimated proved reserves, estimated future net revenues and the discounted present value thereof attributable to the Underlying Properties, 80% of the Underlying Properties and the Net Profits Interest, in each case derived from the reserve reports.


			80% of the
	Underlying		Underlying		Net Profit
	Properties⁽¹⁾		Properties⁽²⁾		Interests
	(In thousands)

Proved Reserves
Oil (MBbls)⁽³⁾		12,766		10,213		5,642
Natural Gas (MMcf)		85,787		68,630		43,058
Oil Equivalents (Mboe)⁽⁴⁾		27,064		21,651		12,818
Future Net Revenue	$	1,344,718	$	1,075,774	$	616,091
Future Production Cost	$	578,014	$	462,411	$	48,895	⁽⁵⁾
Future Development Cost	$	57,674	$	46,139	$	—

Future Net Income	$	709,030	$	567,196	$	567,196
Present Value at 10% Discount Rate⁽⁶⁾	$	349,532	$	279,688	$	279,688
Standardized Measure of Discounted Future Net Cash Flows	$	349,532	$	279,688	$	279,688


⁽¹⁾		Reserve volumes and estimated future net revenues for the Underlying Properties reflect volumes and revenues attributable to Enduro Sponsor’s net interests in the properties comprising the Underlying Properties.


⁽²⁾		Reflects 80% of the proved reserves and future net revenues, production and development costs, net income and present value attributable to the Underlying Properties expected to be produced based on the reserve report.

⁽³⁾		Proved reserves for oil include volumes for NGLs (MBbls) of 183 MBbls, 146 MBbls and 101 MBbls attributable to the Underlying Properties, 80% of the Underlying Properties and the Net Profits Interest, respectively.

⁽⁴⁾		The proved reserves for 80% of the Underlying Properties and the Net Profits Interest of 21,651 Mboe and 12,818 Mboe differ by 8,833 Mboe. Proceeds from the sale of the 8,833 Mboe will be used to cover 80% of the future production and development costs attributable to the Underlying Properties for the benefit of the trust.


⁽⁵⁾		Future production costs for the Net Profits Interest consist solely of severance taxes and ad valorem taxes attributable to the trust.


⁽⁶⁾		The present values of the future net revenues for the Underlying Properties and the Net Profits Interest were determined using a discount rate of 10% per annum. As of December 31, 2010, Enduro Sponsor was structured as a limited liability company. Accordingly, no provision for federal or state income taxes has been provided because taxable income was passed through to the members of Enduro Sponsor.

Changes in Estimated Proved Reserves

The following table summarizes the changes in estimated proved reserves of the Underlying Properties for the periods indicated. The data is presented assuming Enduro Sponsor owned all the Underlying Properties as of December 31, 2007.


							Oil
	Oil			Natural Gas			Equivalents
	(MBbls)			(MMcf)			(MBoe)

Proved Reserves:
Balance, January 1, 2008		16,177			67,009			27,345
Revisions of prior estimates⁽¹⁾		(4,374	)		23,731			(419	)
Production		(1,084	)		(8,868	)		(2,562	)

Balance, December 31, 2008		10,719			81,872			24,364
Revisions of prior estimates⁽¹⁾		2,466			2,705			2,917
Production		(1,016	)		(8,455	)		(2,425	)

Balance, December 31, 2009		12,169			76,122			24,856
Revisions of prior estimates⁽¹⁾		1,536			16,836			4,342
Production		(939	)		(7,171	)		(2,134	)

Balance, December 31, 2010		12,766			85,787			27,064
Proved Developed Reserves:
Balance, December 31, 2008		10,674			67,164			21,868
Balance, December 31, 2009		12,124			57,010			21,626
Balance, December 31, 2010		12,387			51,293			20,935
Proved Undeveloped Reserves:
Balance, December 31, 2008		45			14,708			2,496
Balance, December 31, 2009		45			19,112			3,230
Balance, December 31, 2010		379			34,494			6,129


⁽¹⁾		The Underlying Properties include a portion of the assets in East Texas and North Louisiana acquired by Enduro Sponsor from Denbury in December 2010, and all of the assets in the Permian Basin of New Mexico and West Texas acquired by Enduro Sponsor from Samson and ConocoPhillips in January 2011 and February 2011, respectively. Because Enduro Sponsor did not own the Underlying Properties prior to December 31, 2009, it does not have a detailed reserve reconciliation for the Underlying Properties for that period. Instead, Enduro Sponsor has used reserve information as derived from EAC’s 2008 and 2009 reserve reports, as well as its own reserve report for 2010, and rolled back the data from December 31, 2010 to December 31, 2009 and subsequently to December 31, 2008 for the ConocoPhillips and the Samson acquisitions.

During 2008, there were 138 wells drilled on the Underlying Properties. In the East Texas/North Louisiana region, there were 71 natural gas wells drilled. In the Permian Basin region, 67 vertical oil and natural gas wells were drilled in various fields and formations. The level and success of natural gas well drilling in the Cotton Valley and Hosston formations in East Texas/North Louisiana had a significant impact on the positive revision for natural gas reserves in 2008. There were no Haynesville Shale wells drilled in 2008.

During 2009, there were 46 wells drilled on the Underlying Properties. In the East Texas/North Louisiana region, there were eight natural gas wells drilled with four of these wells being drilled to the Haynesville Shale. In the Permian Basin region, 38 vertical oil and natural gas wells were drilled in various fields and formations. As a result of the drop in the level of the vertical well drilling activity in East Texas/North Louisiana, natural gas reserve revisions were less in 2009.

During 2010, there were 52 wells drilled on the Underlying Properties. In the East Texas/North Louisiana region, there were 11 natural gas wells drilled. In the Permian Basin region, there were 41 oil and natural gas wells drilled vertically. The natural gas reserve revisions were greater than in 2008 and 2009 due to 11 horizontal wells being drilled in the Haynesville Shale in the East Texas/North Louisiana region in 2010.

The combination of a changing price environment together with successful drilling and growth in the Haynesville Shale has caused these fluctuations.

Reserve Estimates

Enduro Sponsor has not filed reserve estimates covering the Underlying Properties with any other federal authority or agency.

Changes in Proved Undeveloped Reserves

Permian Basin Region

In the Permian Basin region, ConocoPhillips received notice in October 2010 of an intent to drill in the Lost Tank field in New Mexico. After significant preparations were made by the operator to drill the wells, Enduro Sponsor recognized eight proved undeveloped well locations in the Lost Tank field in the 2010 reserve report, which represented 595 MBoe of reserves.

In the Permian Basin region, all eight proved undeveloped well locations in the 2010 reserve report relating to the Underlying Properties have been or are in the process of being drilled in 2011. This drilling activity will result in the movement of 595 MBoe of reserves from proved undeveloped in 2010 to proved developed in 2011. Another 10 wells have been spud in 2011 and one well has been proposed and approved by Enduro Sponsor. These 11 wells are not included in the proved undeveloped category in future years in the Permian Basin region.

East Texas/North Louisiana Region

Based in part on the success of offset drilling to Enduro Sponsor’s acreage, Third Party Operators drilled four wells horizontally to the Haynesville Shale formation in 2008. In 2009, the Third Party Operators drilled one horizontal well. In 2010, the drilling pace increased with 11 horizontal wells to the Haynesville Shale formation. As a result of the drilling activity in 2008, 2009 and 2010 and the positive results from that activity, Enduro Sponsor added 14 proved undeveloped well locations in the Haynesville Shale on its acreage in the 2010 reserve report relating to the Underlying Properties, which contributed significantly to the increase in Enduro Sponsor’s proved undeveloped reserves from 2008 to 2010.

Since December 31, 2010, progress has been made to develop proved undeveloped reserves. In the East Texas/North Louisiana region, two of the four wells scheduled for 2011 have been drilled in the Haynesville Shale, which will move 144 MBoe of proved undeveloped reserves in 2010 to the proved developed category in 2011, representing 32% of the proved undeveloped reserves for 2011 in the Kingston and Elm Grove fields. Another 16 wells have been spud or have drilling in progress and eight more wells have been proposed and approved by Enduro Sponsor for the Haynesville Shale in 2011. Of these 26 wells, three wells represent 399 MBoe of reserves (88% of the proved undeveloped reserves for 2011) and are included in the proved undeveloped category for future years in the East Texas/North Louisiana region.

Development of Proved Undeveloped Reserves

All proved undeveloped locations are scheduled to be spud within the next five years. Enduro Sponsor does not recognize proved undeveloped reserves beyond five years.

Sale and Abandonment of Underlying Properties

The operators of the Underlying Properties or any transferee will have the right to abandon its interest in any well or property if it reasonably believes a well or property ceases to produce or is not capable of producing in commercially paying quantities. Upon termination of the lease, the portion of the Net Profits Interest relating to the abandoned property will be extinguished.

Enduro Sponsor generally may sell all or a portion of its interests in the Underlying Properties, subject to and burdened by the Net Profits Interest, without the consent of the trust unitholders. In addition, Enduro Sponsor may, without the consent of the trust unitholders, require the trust to release the Net Profits Interest associated with any lease that accounts for less than or equal to 0.25% of the total production from the Underlying Properties in the prior 12 months and provided that the Net Profits Interest covered by such releases cannot exceed, during any 12-month period, an aggregate fair market value to the trust of $500,000. These releases will be made only in connection with a sale by Enduro Sponsor to a non-affiliate of the relevant Underlying Properties and are conditioned upon the trust receiving an amount equal to the fair value to the trust of such Net Profits Interest. Enduro Sponsor has not identified for sale any of the Underlying Properties.

Hydraulic Fracturing

As of December 31, 2010, all of the total proved reserves associated with the Underlying Properties within the East Texas/North Louisiana region were operated by third party oil and natural gas companies. These Third Party Operators often use hydraulic fracturing as a means to maximize the productivity of oil and natural gas wells. Hydraulic fracturing involves the injection of water, sand and additives under pressure into rock formations in order to stimulate natural gas production. The Third Party Operators often find that the use of hydraulic fracturing is necessary to produce commercial quantities of oil and natural gas from the Haynesville Shale. Many of the Third Party Operators have made extensive public disclosure regarding their hydraulic fracturing activities.

All of Enduro Sponsor’s acreage in the East Texas/North Louisiana region, or 4,113 net acres, representing approximately 39.7% of the proved reserves associated with the Underlying Properties as of December 31, 2010, is subject to hydraulic fracturing. Although the cost of each well will vary, on average approximately 40% of the total cost of drilling and completing a well to the Haynesville Shale formation is associated with hydraulic fracturing activities. These costs are treated in the same way that all other costs of drilling and completing Enduro Sponsor’s wells are treated and are built into Enduro Sponsor’s normal capital expenditure budget, which is funded through operating cash flows or borrowings under its revolving credit facility. Enduro Sponsor owns an average 26.2% working interest in the Haynesville Shale formations associated with the Underlying Properties. Enduro Sponsor has a total $30 million capital expenditure budget for the East Texas/North Louisiana region, approximately $12 million of which is budgeted for hydraulic fracturing activities.

To Enduro Sponsor’s knowledge, there have not been any incidents, citations or suits related to fracturing operations related to environmental concerns on the Underlying Properties. The protection of groundwater quality is extremely important to Enduro Sponsor. Enduro Sponsor has reviewed with the Third Party Operators their responsibilities, plans and policies regarding oil and gas operations and the environment, including hydraulic fracturing. These operators have provided detailed information in their publicly filed documents and on their websites regarding hydraulic fracturing. Enduro Sponsor believes that all of the Third Party Operators using hydraulic fracturing in the East Texas/North Louisiana region follow applicable standard industry practices and legal requirements for groundwater protection. These measures are subject to close supervision by state and federal regulators (including the Bureau of Land Management with respect to federal acreage), who conduct many inspections during operations that include hydraulic fracturing. These protective measures include using steel casing pipe and concrete in well construction.

Once a pipe is set in place, cement is pumped into the well where it hardens and creates a permanent, isolating barrier between the steel casing pipe and surrounding geological formations. This

aspect of the well design is intended to eliminate any “pathway” for the fracturing fluid to contact any aquifers during the hydraulic fracturing operations. Furthermore, in the Haynesville Shale, the hydrocarbon bearing formations are generally separated from any usable underground aquifers by thousands of feet of impermeable rock layers. This wide separation serves as a protective barrier, preventing any migration of fracturing fluids or hydrocarbons upwards into any groundwater zones.

In addition, the vendors conducting hydraulic fracturing in the East Texas/North Louisiana region monitor all pump rates and pressures during the fracturing treatments. This monitoring occurs on a real-time basis to identify abrupt changes in rate or pressure, which permits the operator to modify or cease the fracturing process.

Approximately 99% of typical hydraulic fracturing fluids are made up of water and sand. The Third Party Operators utilize major hydraulic fracturing service companies whose research departments, in cooperation with some Third Party Operators, conduct ongoing development of “greener” chemicals that are used in fracturing.

Many Third Party Operators have made arrangements to source a portion of their water needs from recycled industrial waste water. The Third Party Operators are also currently investigating the technology to recycle a significant percentage of the water recovered from hydraulic fracturing operations in the East Texas/North Louisiana region. This recycling greatly lessens the demand on local natural water resources. Enduro Sponsor believes that any water from hydraulic fracturing operations in the East Texas/North Louisiana region that is not recycled is disposed of in a way that does not impact surface waters, generally by means of approved disposal or injection wells. Enduro Sponsor currently does not intentionally discharge any waters to the surface. The Third Party Operators employ other procedures to reduce the impact of water discharge, including ensuring that produced water is contained in surface tanks or open pits that are properly lined to prevent produced water from being released into the environment. Enduro Sponsor supports the Third Party Operators’ activities to operate responsibly and prudently. In many cases, Enduro Sponsor has joint operating agreements that require the operator to act prudently with respect to safety and the environment.

For more information on the risks of hydraulic fracturing, please read “Risk Factors — The operations of the Underlying Properties are subject to environmental laws and regulations that could adversely affect the cost, manner or feasibility of conducting operations on them or result in significant costs and liabilities, which could reduce the amount of cash available for distribution to trust unitholders.” and “Risk Factors — Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect the services of the operators of the Underlying Properties.”

Marketing and Post-Production Services

Pursuant to the terms of the conveyance creating the Net Profits Interest, Enduro Sponsor will have the responsibility to market, or cause to be marketed, the oil and natural gas production attributable to the Net Profits Interest in the Underlying Properties. The terms of the conveyance restrict Enduro Sponsor from charging any fee for marketing production attributable to the Net Profits Interest other than fees for marketing paid to non-affiliates. Accordingly, a marketing fee will not be deducted (other than fees paid to non-affiliates) in the calculation of the Net Profits Interest’s share of net profits. The net profits to the trust from the sales of oil and natural gas production from the Underlying Properties attributable to the Net Profits Interest will be determined based on the same price that Enduro Sponsor receives for sales of oil and natural gas production attributable to Enduro Sponsor’s interest in the Underlying Properties. However, in the event that the oil or natural gas is processed, the net profits will receive the same processing upgrade or downgrade as Enduro Sponsor.

During the year ended December 31, 2010, the operators of the Underlying Properties sold the oil produced from the Underlying Properties to third-party crude oil purchasers. Oil production from the Underlying Properties is typically transported by truck from the field to the closest gathering facility or refinery. The operators sell the majority of the oil production from the Underlying Properties under

contracts using market sensitive pricing. The price received by the operators for the oil production from the Underlying Properties is usually based on a regional price applied to equal daily quantities in the month of delivery that is then reduced for differentials based upon delivery location and oil quality. Enduro Sponsor does not believe that the loss of any of these parties as a purchaser of crude oil production from the Underlying Properties would have a material impact on the business or operations of Enduro Sponsor or the Underlying Properties because of the competitive marketing conditions in Texas, Louisiana and New Mexico.

All natural gas produced by the operators is marketed and sold to third-party purchasers. The natural gas is sold pursuant to contracts with such third parties, and the sales contracts are in their secondary terms and are on a month-to-month basis. In all cases, the contract price is based on a percentage of a published regional index price, after adjustments for Btu content, transportation and related charges.

Title to Properties

The properties comprising the Underlying Properties are or may be subject to one or more of the burdens and obligations described below. To the extent that these burdens and obligations affect Enduro Sponsor’s rights to production or the value of production from the Underlying Properties, they have been taken into account in calculating the trust’s interests and in estimating the size and the value of the reserves attributable to the Underlying Properties.

Enduro Sponsor’s interests in the oil and natural gas properties comprising the Underlying Properties are typically subject, in one degree or another, to one or more of the following:


	•	royalties and other burdens, express and implied, under oil and natural gas leases and other arrangements;

	•	overriding royalties, production payments and similar interests and other burdens created by Enduro Sponsor’s predecessors in title;

	•	a variety of contractual obligations arising under operating agreements, farm-out agreements, production sales contracts and other agreements that may affect the Underlying Properties or their title;

	•	liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing unpaid suppliers and contractors and contractual liens under operating agreements that are not yet delinquent or, if delinquent, are being contested in good faith by appropriate proceedings;

	•	pooling, unitization and communitization agreements, declarations and orders;

	•	easements, restrictions, rights-of-way and other matters that commonly affect property;

	•	conventional rights of reassignment that obligate Enduro Sponsor to reassign all or part of a property to a third party if Enduro Sponsor intends to release or abandon such property;

	•	preferential rights to purchase or similar agreements and required third party consents to assignments or similar agreements;

	•	obligations or duties affecting the Underlying Properties to any municipality or public authority with respect to any franchise, grant, license or permit, and all applicable laws, rules, regulations and orders of any governmental authority; and

	•	rights reserved to or vested in the appropriate governmental agency or authority to control or regulate the Underlying Properties and also the interests held therein, including Enduro Sponsor’s interests and the Net Profits Interest.

Enduro Sponsor believes that the burdens and obligations affecting the properties comprising the Underlying Properties are conventional in the industry for similar properties. Enduro Sponsor also

believes that the existing burdens and obligations do not, in the aggregate, materially interfere with the use of the Underlying Properties and will not materially adversely affect the Net Profits Interest or its value.

In order to give third parties notice of the Net Profits Interest, Enduro Sponsor will record the conveyance of the Net Profits Interest in Texas, Louisiana and New Mexico in the real property records in each Texas, Louisiana or New Mexico county in which the Underlying Properties are located, or in such other public records of those states as required under applicable law to place third parties on notice of the conveyance.

It is well-established under Texas law that the conveyance of a net profits interest constitutes the conveyance of a presently vested, non-possessory interest in real property. Therefore, Enduro Sponsor and the trust believe that, in a bankruptcy of Enduro Sponsor, the Net Profits Interest would be viewed as a separate property interest under Texas law and, as such, outside of Enduro Sponsor’s bankruptcy estate. Likewise, Enduro Sponsor and the trust believe that the Net Profits Interest would be viewed as a separate property interest under the laws of Louisiana and outside of Enduro Sponsor’s bankruptcy estate. Since enactment of the Louisiana Mineral Code in 1975, Louisiana courts have classified an overriding royalty interest as a real right and an incorporeal immovable (similar to a real property interest). Although there are no reported Louisiana court cases addressing whether a net profits interest, carved out of the interest of a mineral lessee under an oil and gas lease, should be similarly classified as a real right and an incorporeal immovable, a 1972 Colorado federal court applying Louisiana law did conclude that such a net profits interest was comparable to an overriding royalty interest and, thus, was properly so classified. Similarly, Enduro Sponsor and the trust believe that a New Mexico court would rule that the conveyance of a net profits interest constitutes a conveyance of a real property interest. While no New Mexico case has clearly defined the nature of a “net profits interest” independent of the creating instrument, New Mexico case law has held that an overriding royalty interest in a mineral lease is a real property interest under New Mexico law. The 10th Circuit Court of Appeals has held that a net profits interest is “similar to” an overriding royalty interest. Given that the conveyance of the Net Profits Interest will contain a provision stating that it is the express intent of the parties that the conveyance of the Net Profits Interest constitutes a conveyance of a royalty interest in real property, in the event of a bankruptcy on the part of Enduro Sponsor, under New Mexico law, the Net Profits Interest would likely not be treated as part of Enduro Sponsor’s bankruptcy estate. Further, it is relevant that Enduro Sponsor and the trust have structured the Net Profits Interest as an overriding royalty interest in gross production payable on the basis of net profits. Nevertheless, the outcome is not certain given that there are not any dispositive Louisiana or New Mexico Supreme Court cases directly concluding that a conveyance of a net profits interest: (i) in the case of Louisiana, constitutes the conveyance of a real right and an incorporeal immovable (similar to a real property interest) or (ii) in the case of New Mexico, the conveyance of a real property interest. As such, in a bankruptcy of Enduro Sponsor, to the extent Louisiana or New Mexico law were held to be applicable, the Net Profits Interest might be considered an asset of the bankruptcy estate and used to satisfy obligations to creditors of Enduro Sponsor, in which case the trust would be an unsecured creditor of Enduro Sponsor at risk of losing the entire value of the Net Profits Interest to senior creditors.

Enduro Sponsor believes that its title to the Underlying Properties is, and the trust’s title to the Net Profits Interest will be, good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions as are not so material to detract substantially from the use or value of such properties or royalty interests. Under the terms of the conveyance creating the Net Profits Interest, Enduro Sponsor has provided a special warranty of title with respect to the Net Profits Interest, subject to the burdens and obligations described in this section. Please see “Risk Factors — The trust units may lose value as a result of title deficiencies with respect to the Underlying Properties.”

Competition and Markets

The oil and natural gas industry is highly competitive. Enduro Sponsor competes with major oil and natural gas companies and independent oil and natural gas companies for oil and natural gas, equipment, personnel and markets for the sale of oil and natural gas. Many of these competitors are financially stronger than Enduro Sponsor, but even financially troubled competitors can affect the market because of their need to sell oil and natural gas at any price to attempt to maintain cash flow. The trust will be subject to the same competitive conditions as Enduro Sponsor and other companies in the oil and natural gas industry.

Oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the availability or price of oil, natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas.

Future price fluctuations for oil and natural gas will directly impact trust distributions, estimates of reserves attributable to the trust’s interests and estimated and actual future net revenues to the trust. In view of the many uncertainties that affect the supply and demand for oil and natural gas, neither the trust nor Enduro Sponsor can make reliable predictions of future oil and natural gas supply and demand, future product prices or the effect of future product prices on the trust.

Environmental Matters and Regulation

General. The oil and natural gas exploration and production operations of Enduro Sponsor are subject to stringent and comprehensive federal, regional, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may impose significant obligations on Enduro Sponsor’s operations, including requirements to:


	•	obtain permits to conduct regulated activities;

	•	limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas;

	•	restrict the types, quantities and concentration of materials that can be released into the environment in the performance of drilling and production activities;

	•	initiate investigatory and remedial measures to mitigate pollution from former or current operations, such as restoration of drilling pits and plugging of abandoned wells;

	•	apply specific health and safety criteria addressing worker protection; and

	•	impose substantial liabilities on Enduro Sponsor for pollution resulting from Enduro Sponsor’s operations.

Failure to comply with environmental laws and regulations may result in the assessment of administrative, civil and criminal sanctions, including monetary penalties, the imposition of joint and several liability, investigatory and remedial obligations, and the issuance of injunctions limiting or prohibiting some or all of Enduro Sponsor’s operations. Moreover, these laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Enduro Sponsor believes that it is in substantial compliance with all existing environmental laws and regulations applicable to its current operations and that its continued compliance with existing requirements will not have a material adverse effect on the cash distributions to the trust unitholders. However, the clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or re-interpretation of enforcement policies that result

in more stringent and costly construction, drilling, water management, completion, emission or discharge limits or waste handling, disposal or remediation obligations could have a material adverse effect on Enduro Sponsor’s development expenses, results of operations and financial position. Enduro Sponsor may be unable to pass on those increases to its customers. Moreover, accidental releases or spills may occur in the course of Enduro Sponsor’s operations, and Enduro Sponsor cannot assure you that it will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons.

The following is a summary of certain existing environmental, health and safety laws and regulations, each as amended from time to time, to which Enduro Sponsor’s business operations are subject.

Hazardous substance and wastes. The Comprehensive Environmental Response, Compensation and Liability Act, or “CERCLA,” also known as the Superfund law, and comparable state laws impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. Under CERCLA, these “responsible persons” may include the owner or operator of the site where the release occurred, and entities that transport, dispose of or arrange for the transport or disposal of hazardous substances released at the site. These responsible persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Enduro Sponsor generates materials in the course of its operations that may be regulated as hazardous substances.

The Resource Conservation and Recovery Act, or “RCRA,” and comparable state laws regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the EPA, most states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration, production and development of crude oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes (“E&P Wastes”) now classified as non-hazardous could be classified as hazardous wastes in the future. In September 2010, the Natural Resources Defense Council filed a petition with the EPA to request reconsideration of the exemption of E&P Wastes from regulation as hazardous waste under RCRA (which could also affect E&P Wastes’ regulation under other environmental laws, including CERCLA). Any such change could result in an increase in the costs to manage and dispose of wastes, which could have a material adverse effect on the cash distributions to the trust unitholders. In addition, Enduro Sponsor generates industrial wastes in the ordinary course of its operations that may be regulated as hazardous wastes.

The real properties upon which Enduro Sponsor conducts its operations have been used for oil and natural gas exploration and production for many years. Although Enduro Sponsor may have utilized operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons and wastes may have been disposed of or released on or under the real properties upon which Enduro Sponsor conducts its operations, or on or under other, offsite locations, where these petroleum hydrocarbons and wastes have been taken for recycling or disposal. In addition, the real properties upon which Enduro Sponsor conducts its operations may have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or hydrocarbons was not under Enduro Sponsor’s control. These real properties and the petroleum hydrocarbons and wastes disposed or released thereon may be subject to CERCLA, RCRA and analogous state laws. Under such laws, Enduro Sponsor could be required to remove or remediate

previously disposed wastes, to clean up contaminated property and to perform remedial operations such as restoration of pits and plugging of abandoned wells to prevent future contamination or to pay some or all of the costs of any such action.

Water discharges and hydraulic fracturing. The Federal Water Pollution Control Act, also known as the “Clean Water Act,” and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil, into federal and state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. Spill prevention, control and countermeasure, or SPCC, plan requirements imposed under the Clean Water Act require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws required individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The Oil Pollution Act of 1990, as amended, or OPA, amends the Clean Water Act and establishes strict liability and natural resource damages liability for unauthorized discharges of oil into waters of the United States. OPA requires owners or operators of certain onshore facilities to prepare Facility Response Plans for responding to a worst case discharge of oil into waters of the United States.

In addition, naturally occurring radioactive material (“NORM”) is brought to the surface in connection with oil and gas production. Concerns have arisen over traditional NORM disposal practices (including discharge through publicly owned treatment works into surface waters), which may increase the costs associated with management of NORM.

It is customary to recover oil and natural gas from deep shale and tight sand formations through the use of hydraulic fracturing, combined with sophisticated horizontal drilling. Hydraulic fracturing involves the injection of water, sand and chemical additives under pressure into rock formations to stimulate gas production. Due to public concerns raised regarding potential impacts of hydraulic fracturing on groundwater quality, legislative and regulatory efforts at the federal level and in some states have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. Legislation called the FRAC Act has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. The EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with results of the study anticipated to be available by late 2012. The results of this study could spur further action toward federal legislation and regulation of hydraulic fracturing activities. Other federal agencies are examining hydraulic fracturing, including the U.S. DOE, the U.S. Government Accountability Office and the White House Council for Environmental Quality, and the U.S. Department of the Interior is also considering regulation of hydraulic fracturing activities on public lands. In addition, legislation called the FRAC Act has been introduced in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Also some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances, including states in which Enduro Sponsor operates. For example, on June 17, 2011, Texas signed into law a bill that requires the disclosure of information regarding the substances used in the hydraulic fracturing process to the Railroad Commission of Texas (the entity that regulates oil and natural gas production) and the public. In addition, at least three local governments in Texas have imposed temporary moratoria on drilling permits within city limits so that local ordinances may be reviewed to assess their adequacy to address such activities. Disclosures of chemicals used in the hydraulic fracturing process could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could make it more difficult or costly for

Enduro Sponsor to perform hydraulic fracturing activities. Moreover, Enduro Sponsor believes that enactment of legislation regulating hydraulic fracturing at the federal level may have a material adverse effect on its business. In addition, the EPA recently took the position that hydraulic fracturing operations using diesel are subject to regulation under the Underground Injection Control program of the Safe Drinking Water Act as Class II wells. Such regulation could result in increased costs and operational delays for certain hydraulic fracturing operations.

Air emissions. The federal Clean Air Act and comparable state laws restrict the emission of air pollutants from many sources through air emissions permitting programs and also impose various monitoring and reporting requirements. These laws and regulations may require Enduro Sponsor to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or incur development expenses to install and utilize specific equipment or technologies to control emissions. Obtaining permits has the potential to delay the development of oil and natural gas projects. Federal and state regulatory agencies may impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations.

Climate change. Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” or “GHGs,” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to the scientific studies, international negotiations to address climate change have occurred. The United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol,” became effective on February 16, 2005 as a result of these negotiations, but the United States did not ratify the Kyoto Protocol. At the end of 2009, an international conference to develop a successor to the Kyoto Protocol issued a document known as the Copenhagen Accord. Pursuant to the Copenhagen Accord, the United States submitted a greenhouse gas emission reduction target of 17 percent compared to 2005 levels.

Both houses of Congress have actively considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. These allowances would be expected to escalate significantly in cost over time. Although it is not possible at this time to predict when Congress may pass climate change legislation, any future federal or state laws that may be adopted to address GHG emissions could require Enduro Sponsor to incur increased operating costs and could adversely affect demand for the oil and natural gas Enduro Sponsor produces.

In addition, on December 15, 2009, the EPA published its findings that emissions of GHGs present an endangerment to public heath and the environment. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA has adopted two sets of regulations under the Clean Air Act. The first limits emissions of GHGs from motor vehicles beginning with the 2012 model year. The EPA has asserted that these final motor vehicle GHG emission standards trigger Clean Air Act construction and operating permit requirements for stationary sources, commencing when the motor vehicle standards take effect on January 2, 2011. On June 3, 2010, the EPA published its final rule to address the permitting of GHG emissions from stationary sources under PSD and Title V permitting programs. This rule “tailors” these permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. It is widely expected that facilities required to obtain PSD permits for their GHG emissions also will be required to reduce those emissions according to “best available control technology” standards for GHG that have yet to be developed. In December 2010, the EPA promulgated Federal Implementation Plans to establish GHG permitting under the PSD program in several jurisdictions in which applicable State Implementation

Plans did not accommodate the regulation of GHGs. In many other jurisdictions, applicable State Implementation Plans may provide for GHG permitting under the PSD program. In addition, on November 30, 2010, the EPA published its final rule expanding the existing GHG monitoring and reporting rule to include onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities. Reporting of GHG emissions from such facilities will be required on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011. The Underlying Properties may be subject to these requirements or become subject to them in the future.

Because regulation of GHG emissions is relatively new, further regulatory, legislative and judicial developments are likely to occur. Such developments may affect how these GHG initiatives will impact Enduro Sponsor’s operations. In addition to these regulatory developments, recent judicial decisions that have allowed certain tort claims alleging property damage to proceed against GHG emissions sources may increase Enduro Sponsor’s litigation risk for such claims. The adoption of any future regulations that require reporting of GHGs or otherwise limit emissions of GHGs from the equipment and operations of Enduro Sponsor could require Enduro Sponsor to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with its operations, and such requirements also could adversely affect demand for the oil and natural gas that Enduro Sponsor produces.

Legislation or regulations that may be adopted to address climate change could also affect the markets for Enduro Sponsor’s products by making its products more or less desirable than competing sources of energy. To the extent that its products are competing with higher greenhouse gas emitting energy sources, Enduro Sponsor’s products would become more desirable in the market with more stringent limitations on greenhouse gas emissions. To the extent that its products are competing with lower greenhouse gas emitting energy, Enduro Sponsor’s products would become less desirable in the market with more stringent limitations on greenhouse gas emissions. Enduro Sponsor cannot predict with any certainty at this time how these possibilities may affect its operations.

Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for the oil or natural gas produced by Enduro Sponsor or otherwise cause Enduro Sponsor to incur significant costs in preparing for or responding to those effects.

National Environmental Policy Act. Oil and natural gas exploration, development and production activities on federal lands are subject to the National Environmental Policy Act, as amended, or NEPA. NEPA requires federal agencies, including the Department of the Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. However, for those current activities as well as for future or proposed exploration and development plans on federal lands, governmental permits or authorizations that are subject to the requirements of NEPA are required. This process has the potential to delay the development of oil and natural gas projects.

Endangered Species Act. The federal Endangered Species Act, or “ESA,” restricts activities that may affect endangered and threatened species or their habitats. The designation of previously unidentified endangered or threatened species could cause Enduro Sponsor to incur additional costs or become subject to operating delays, restrictions or bans in the affected areas. For example, the U.S. Fish and Wildlife Service has proposed to list as “endangered” the dunes sagebrush lizard (Sceloporus arenicolus), whose habitat is understood to include areas in West Texas and southeast New Mexico in which some of the Underlying Properties are located. While some of Enduro Sponsor’s facilities or leased acreage may be located in areas that are or will be designated as habitat for

endangered or threatened species, Enduro Sponsor believes that it is in substantial compliance with the ESA.

Employee health and safety. The operations of Enduro Sponsor are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, or “OSHA,” and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. Enduro Sponsor believes that it is in substantial compliance with all applicable laws and regulations relating to worker health and safety.

COMPUTATION OF NET PROFITS

The provisions of the conveyance governing the computation of the net profits are detailed and extensive. The following information summarizes the material information contained in the conveyance related to the computation of the net profits. This summary may not contain all information that is important to you. For more detailed provisions concerning the Net Profits Interest, you should read the conveyance. A copy of the conveyance has been filed as an exhibit to the registration statement. See “Where You Can Find More Information.”

Net Profits Interest

The amounts paid to the trust for the Net Profits Interest are based on, among other things, the definitions of “gross profits” and “net profits” contained in the conveyance and described below. Under the conveyance, net profits are computed monthly, and 80% of the aggregate net profits attributable to the sale of oil and natural gas production from the Underlying Properties for each calendar month will be paid to the trust on or before the end of the following month. Enduro Sponsor will not pay to the trust any interest on the net profits held by Enduro Sponsor prior to payment to the trust, provided that such payments are timely made. The trustee will make distributions to trust unitholders monthly. See “Description of the Trust Units — Distributions and Income Computations.”

“Gross profits” means the aggregate amount received by Enduro Sponsor from sales of oil and natural gas produced from the Underlying Properties (after deducting the appropriate share of all royalties and any overriding royalties, production payments and other similar charges (in each case, in existence as of May 1, 2011) and other than certain excluded proceeds, as described in the conveyance), including all proceeds and consideration received (i) for advance payments, (ii) under take-or-pay and similar provisions of production sales contracts (when credited against the price for delivery of production) and (iii) under balancing arrangements. Gross profits do not include consideration for the transfer or sale of any Underlying Property by Enduro Sponsor or any subsequent owner to any new owner, unless the Net Profits Interest is released (as is permitted under certain circumstances). Gross profit also does not include any amount for oil or natural gas lost in production or marketing or used by the owner of the Underlying Properties in drilling, production and plant operations.

“Net profits” means gross profits less the following costs, expenses and, where applicable, losses, liabilities and damages all as actually incurred by Enduro Sponsor and attributable to the Underlying Properties on or after May 1, 2011 (as such items are reduced by any offset amounts, as described in the conveyance):


	•	all costs for (i) drilling, development, production and abandonment operations, (ii) all direct labor and other services necessary for drilling, operating, producing and maintaining the Underlying Properties and workovers of any wells located on the Underlying Properties, (iii) treatment, dehydration, compression, separation and transportation, (iv) all materials purchased for use on, or in connection with, any of the Underlying Properties and (v) any other operations with respect to the exploration, development or operation of hydrocarbons from the Underlying Properties;

	•	all losses, costs, expenses, liabilities and damages with respect to the operation or maintenance of the Underlying Properties for (i) defending, prosecuting, handling, investigating or settling litigation, administrative proceedings, claims, damages, judgments, fines, penalties and other liabilities, (ii) the payment of certain judgments, penalties and other liabilities, (iii) the payment or restitution of any proceeds of hydrocarbons from the Underlying Properties, (iv) complying with applicable local, state and federal statutes, ordinances, rules and regulations, (v) tax or royalty audits and (vi) any other loss, cost, expense, liability or damage with respect to the Underlying Properties not paid or reimbursed under insurance;


	•	all taxes, charges and assessments (excluding federal and state income, transfer, mortgage, inheritance, estate, franchise and like taxes) with respect to the ownership of, or production of hydrocarbons from, the Underlying Properties;

	•	all insurance premiums attributable to the ownership or operation of the Underlying Properties for insurance actually carried with respect to the Underlying Properties, or any equipment located on any of the Underlying Properties, or incident to the operation or maintenance of the Underlying Properties;

	•	all amounts and other consideration for (i) rent and the use of or damage to the surface, (ii) delay rentals, shut-in well payments and similar payments and (iii) fees for renewal, extension, modification, amendment, replacement or supplementation of the leases included in the Underlying Properties;

	•	all amounts charged by the relevant operator as overhead, administrative or indirect charges specified in the applicable operating agreements or other arrangements covering the Underlying Properties or Enduro Sponsor’s operations with respect thereto;

	•	to the extent that Enduro Sponsor is the operator of certain of the Underlying Properties and there is no operating agreement covering such portion of the Underlying Properties, those overhead, administrative or indirect charges that are allocated by Enduro Sponsor to such portion of the Underlying Properties;

	•	if, as a result of the occurrence of the bankruptcy or insolvency or similar occurrence of any purchaser of hydrocarbons produced from the Underlying Properties, any amounts previously credited to the determination of the net profits are reclaimed from Enduro Sponsor, then the amounts reclaimed;

	•	all costs and expenses for recording the conveyance and, at the applicable times, terminations and/or releases thereof;

	•	all administrative hedge costs (in respect of hedges existing prior to the date of the conveyance, as further described in the conveyance);

	•	all hedge settlement costs paid (in respect of hedges existing prior to the date of the conveyance, as further described in the conveyance);

	•	amounts previously included in gross profits but subsequently paid as a refund, interest or penalty; and

	•	at the option of Enduro Sponsor (or any subsequent owner of the Underlying Properties), amounts reserved for approved development expenditure projects, including well drilling, recompletion and workover costs, which amounts will at no time exceed $2.0 million in the aggregate, and will be subject to the limitations described below (provided that such costs shall not be debited from gross profits when actually incurred).

As mentioned above, the costs deducted in the net profits determination will be reduced by certain offset amounts. The offset amounts are further described in the conveyance, and include, among other things, any proceeds attributable to the treatment or processing of hydrocarbons produced from the Underlying Properties, all of the hedge payments received by Enduro Sponsor from hedge contract counterparties upon settlement of hedge contracts and certain other non-production revenues, including salvage value for equipment related to plugged and abandoned wells. If the offset amounts exceed the costs during a monthly period, the ability to use such excess amounts to offset costs will be deferred and utilized as offsets in the next monthly period to the extent such amounts, plus accrued interest thereon, together with other offsets to costs, for the applicable month, are less than the costs arising in such month.

The trust is not liable to the owners of the Underlying Properties or the operators for any operating, capital or other costs or liabilities attributable to the Underlying Properties. In the event that

the net profits for any computation period is a negative amount, the trust will receive no payment for that period, and any such negative amount plus accrued interest will be deducted from gross profits in the following computation period for purposes of determining the net profits for that following computation period.

Gross profits and net profits are calculated on a cash basis, except that certain costs, primarily ad valorem taxes and expenditures of a material amount, may be determined on an accrual basis.

Additional Provisions

If a controversy arises as to the sales price of any production, then for purposes of determining gross profits:


	•	any proceeds that are withheld for any reason (other than at the request of Enduro Sponsor) are not considered received until such time that the proceeds are actually collected;

	•	amounts received and promptly deposited with a nonaffiliated escrow agent will not be considered to have been received until disbursed to it by the escrow agent; and

	•	amounts received and not deposited with an escrow agent will be considered to have been received.

The trustee is not obligated to return any cash received from the Net Profits Interest. Any overpayments made to the trust by Enduro Sponsor due to adjustments to prior calculations of net profits or otherwise will reduce future amounts payable to the trust until Enduro Sponsor recovers the overpayments plus interest at a prime rate (as described in the conveyance).

The conveyance generally permits Enduro Sponsor to transfer without the consent or approval of the trust unitholders all or any part of its interest in the Underlying Properties, subject to the Net Profits Interest. The trust unitholders are not entitled to any proceeds of a sale or transfer of Enduro Sponsor’s interest. Except in certain cases where the Net Profits Interest is released, following a sale or transfer, the Underlying Properties will continue to be subject to the Net Profits Interest, and the gross profits attributable to the transferred property will be calculated (as part of the computation of net profits described in this prospectus), paid and distributed by the transferee to the trust. Enduro Sponsor will have no further obligations, requirements or responsibilities with respect to any such transferred interests.

In addition, Enduro Sponsor may, without the consent of the trust unitholders, require the trust to release the Net Profits Interest associated with any lease that accounts for less than or equal to 0.25% of the total production from the Underlying Properties in the prior 12 months, provided that the Net Profits Interest covered by such releases cannot exceed, during any 12-month period, an aggregate fair market value to the trust of $500,000. These releases will be made only in connection with a sale by Enduro Sponsor to a non-affiliate of the relevant Underlying Properties and are conditioned upon the trust receiving an amount equal to the fair value to the trust of such Net Profits Interest. Enduro Sponsor has not identified for sale any of the Underlying Properties.

As the designated operator of a property comprising the Underlying Properties, Enduro Sponsor may enter into farm-out, operating, participation and other similar agreements to develop the property, but any transfers made in connection with such agreements will be made subject to the Net Profits Interest. Enduro Sponsor may enter into any of these agreements without the consent or approval of the trustee or any trust unitholder.

Enduro Sponsor will have the right to release, surrender or abandon its interest in any Underlying Property that will no longer produce (or be capable of producing) hydrocarbons in paying quantities (determined without regard to the Net Profits Interest). Upon such release, surrender or abandonment, the portion of the Net Profits Interest relating to the affected property will also be released, surrendered or abandoned, as applicable. Enduro Sponsor will also have the right to abandon an interest in the Underlying Properties if (a) such abandonment is necessary for health, safety or

environmental reasons or (b) the hydrocarbons that would have been produced from the abandoned portion of the Underlying Properties would reasonably be expected to be produced from wells located on the remaining portion of the Underlying Properties.

Enduro Sponsor must maintain books and records sufficient to determine the amounts payable for the Net Profits Interest to the trust. Monthly and annually, Enduro Sponsor must deliver to the trustee a statement of the computation of the net profits for each computation period. The trustee has the right to inspect and review the books and records maintained by Enduro Sponsor during normal business hours and upon reasonable notice.

DESCRIPTION OF THE TRUST AGREEMENT

The following information and the information included under “Description of the Trust Units” summarize the material information contained in the trust agreement and the conveyance. For more detailed provisions concerning the trust and the conveyance, you should read the trust agreement and the conveyance, copies of which will be filed as exhibits to the registration statement. See “Where You Can Find More Information.”

Creation and Organization of the Trust; Amendments

Immediately prior to the closing of this offering, Enduro Sponsor will contribute to the trust the Net Profits Interest in consideration of the receipt of [ ] trust units. The trust’s first monthly distribution will consist of an amount in cash paid by Enduro Sponsor equal to the amount that would have been payable to the trust had the Net Profits Interest been in effect beginning on May 1, 2011, less any general and administrative expenses and reserves of the trust. After the offering made hereby, Enduro Sponsor will own its net interests in the Underlying Properties subject to and burdened by the Net Profits Interest.

The trust was created under Delaware law to acquire and hold the Net Profits Interest for the benefit of the trust unitholders pursuant to an agreement among Enduro Sponsor, the trustee and the Delaware trustee. The Net Profits Interest is passive in nature and neither the trust nor the trustee has any control over or responsibility for costs relating to the operation of the properties comprising the Underlying Properties. Neither Enduro Sponsor nor any of the Third Party Operators have any contractual commitments to the trust to provide additional funding or to conduct further drilling on or to maintain their ownership interest in any of the Underlying Properties. After the conveyance of the Net Profits Interest, however, Enduro Sponsor will retain an interest in the Underlying Properties. For a description of the Underlying Properties and other information relating to them, see “The Underlying Properties.”

The trust agreement will provide that the trust’s business activities will be limited to owning the Net Profits Interest and any activity reasonably related to such ownership, including activities required or permitted by the terms of the conveyance related to the Net Profits Interest. As a result, the trust will not be permitted to acquire other oil and natural gas properties or net profits interests or otherwise to engage in activities beyond those necessary for the conservation and protection of the Net Profits Interest.

The beneficial interest in the trust is divided into [ ] trust units. Each of the trust units represents an equal undivided beneficial interest in the assets of the trust. You will find additional information concerning the trust units in “Description of the Trust Units.”

Amendment of the trust agreement requires the affirmative vote of the holders of at least 75% of the outstanding trust units. However, no amendment may:


	•	increase the power of the trustee or the Delaware trustee to engage in business or investment activities; or

	•	alter the rights of the trust unitholders as among themselves.

Certain amendments to the trust agreement do not require the vote of the trust unitholders. The trustee may, without approval of the trust unitholders, from time to time supplement or amend the trust agreement in order to cure any ambiguity, to correct or supplement any defective or inconsistent provisions, to grant any benefit to all of the trust unitholders, to comply with changes in applicable law or to change the name of the trust, provided such supplement or amendment is not materially adverse to the interests of the trust unitholders. The affairs of the trust will be managed by the trustee. Enduro Sponsor has no ability to manage or influence the operations of the trust and will not owe any fiduciary duties or liabilities to the trust or the unitholders. Likewise, the trust has no ability to manage or influence the operation of Enduro Sponsor.

Assets of the Trust

Upon completion of this offering, the assets of the trust will consist of the Net Profits Interest and any cash and temporary investments being held for the payment of expenses and liabilities and for distribution to the trust unitholders.

Duties and Powers of the Trustee

The duties of the trustee are specified in the trust agreement and by the laws of the state of Delaware, except as modified by the trust agreement. The trustee’s principal duties consist of:


	•	collecting cash attributable to the Net Profits Interest;

	•	paying expenses, charges and obligations of the trust from the trust’s assets;

	•	distributing distributable cash to the trust unitholders;

	•	causing to be prepared and distributed a tax information report for each trust unitholder and to prepare and file tax returns on behalf of the trust;


	•	causing to be prepared and filed reports required to be filed under the Exchange Act and by the rules of any securities exchange or quotation system on which the trust units are listed or admitted to trading;


	•	causing to be prepared and filed a reserve report by or for the trust by independent reserve engineers as of December 31 of each year in accordance with criteria established by the SEC;

	•	establishing, evaluating and maintaining a system of internal control over financial reporting in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002;

	•	enforcing the rights under certain agreements entered into in connection with this offering; and

	•	taking any action it deems necessary and advisable to best achieve the purposes of the trust.

In connection with the formation of the trust, the trust will enter into several agreements with Enduro Sponsor that impose obligations upon Enduro Sponsor that are enforceable by the trustee on behalf of the trust, including a conveyance and a registration rights agreement. The trustee has the power and authority under the trust agreement to enforce these agreements on behalf of the trust. Additionally, the trustee may from time to time supplement or amend the conveyance and the registration rights agreement to which the trust is a party without the approval of trust unitholders in order to cure any ambiguity, to correct or supplement any defective or inconsistent provisions, to grant any benefit to all of the trust unitholders, to comply with changes in applicable law or to change the name of the trust. Such supplement or amendment, however, may not materially adversely affect the interests of the trust unitholders.

The trustee may create a cash reserve to pay for future liabilities of the trust. If the trustee determines that the cash on hand and the cash to be received are, or are reasonably likely to be, insufficient to cover the trust’s liabilities, the trustee may cause the trust to borrow funds to pay liabilities of the trust. The trustee may cause the trust to borrow the funds from any person, including itself or its affiliates. The trustee may also cause the trust to mortgage its assets to secure payment of the indebtedness. If the trust does not have sufficient cash to pay future liabilities, it may, in limited circumstances, sell all or a portion of the Net Profits Interest. The terms of such indebtedness and security interest, if funds were loaned by the entity serving as trustee or Delaware trustee or an affiliate thereof, would be similar to the terms which such entity would grant to a similarly situated commercial customer with whom it did not have a fiduciary relationship, and such entity shall be entitled to

enforce its rights with respect to any such indebtedness and security interest as if it were not then serving as trustee or Delaware trustee. If the trustee causes the trust to borrow funds, the trust unitholders will not receive distributions until the borrowed funds are repaid.

Each month, the trustee will pay trust obligations and expenses and distribute to the trust unitholders the remaining proceeds received from the Net Profits Interest. The cash held by the trustee as a reserve against future liabilities or for distribution at the next distribution date must be invested in:


	•	interest bearing obligations of the United States government;

	•	money market funds that invest only in United States government securities;

	•	repurchase agreements secured by interest-bearing obligations of the United States government; or

	•	bank certificates of deposit.

The trust may not acquire any asset except the Net Profits Interest, cash and temporary cash investments, and it may not engage in any investment activity except investing cash on hand.

The trust may merge or consolidate with or convert into one or more limited partnerships, general partnerships, corporations, business trusts, limited liability companies, associations or unincorporated businesses if such transaction is agreed to by the trustee and by the affirmative vote of the holders of a majority of the trust units present in person or by proxy at a meeting of such holders where a quorum is present and such transaction is permitted under the Delaware Statutory Trust Act and any other applicable law.

Enduro Sponsor may request that the trustee sell all or a portion of its Net Profits Interest under any of the following circumstances:


	•	the sale does not involve a material part of the trust’s assets; or

	•	the sale constitutes a material part of the trust’s assets, subject to the approval of the holders of at least 75% of the outstanding trust units.

The trustee will distribute the net proceeds from any sale of the Net Profits Interest and other assets to the trust unitholders.

Upon dissolution of the trust, the trustee must sell the Net Profits Interest. No trust unitholder approval is required in this event.

The trustee may require any trust unitholder to dispose of his trust units if an administrative or judicial proceeding seeks to cancel or forfeit any of the property in which the trust holds an interest because of the nationality or any other status of that trust unitholder. If a trust unitholder fails to dispose of his trust units, the trustee has the right to purchase them and to borrow funds to make that purchase.

The trustee will be required by the NYSE to maintain a website for filings made by the trust with the SEC.

The trustee may agree to modifications of the terms of the conveyance or to settle disputes involving the conveyance. The trustee may not agree to modifications or settle disputes involving the Net Profits Interest part of the conveyance if these actions would change the character of the Net Profits Interest in such a way that the Net Profits Interest becomes a working interest or that the trust would fail to continue to qualify as a grantor trust for U.S. federal income tax purposes.

Fees and Expenses

Because the trust does not conduct an active business and the trustee has little power to incur obligations, it is expected that the trust will only incur liabilities for routine administrative expenses, such as the trustee’s fees, accounting, engineering, legal, tax advisory and other professional fees and

other fees and expenses applicable to public companies. The trust will also be responsible for paying other expenses incurred as a result of being a publicly traded entity, including costs associated with annual, quarterly and monthly reports to trust unitholders, tax return and Form 1099 preparation and distribution, NYSE listing fees, independent auditor fees and registrar and transfer agent fees. These general and administrative expenses are anticipated to be approximately $850,000 for 2011. General and administrative expenses for subsequent years could be greater or less depending on future events that cannot be predicted. Included in the $850,000 annual estimate is an annual administrative fee of $200,000 and $2,000 for the trustee and Delaware trustee, respectively. See “The Trust.” The trust will pay, out of the first cash payment received by the trust, the trustee’s and Delaware trustee’s legal expenses incurred in forming the trust as well as their acceptance fees in the amount of $10,000 and $1,500, respectively. These costs will be deducted by the trust before distributions are made to trust unitholders.

Fiduciary Responsibility and Liability of the Trustee

The trustee will not make business or investment decisions affecting the assets of the trust except to the extent it enforces its rights under the conveyance agreement related to the Net Profits Interest described above under “— Duties and Powers of the Trustee” that will be executed in connection with this offering. Therefore, substantially all of the trustee’s functions under the trust agreement are expected to be ministerial in nature. See “— Duties and Powers of the Trustee” above. The trust agreement, however, provides that the trustee may:


	•	charge for its services as trustee;

	•	retain funds to pay for future expenses and deposit them with one or more banks or financial institutions (which may include the trustee to the extent permitted by law);

	•	lend funds at commercial rates to the trust to pay the trust’s expenses; and

	•	seek reimbursement from the trust for its out-of-pocket expenses.

In discharging its duty to trust unitholders, the trustee may act in its discretion and will be liable to the trust unitholders only for its own fraud, gross negligence or willful misconduct. The trustee will not be liable for any act or omission of its agents or employees unless the trustee acted in bad faith or with gross negligence in their selection and retention. The trustee will be indemnified individually or as the trustee for any liability or cost that it incurs in the administration of the trust, except in cases of fraud, gross negligence or willful misconduct. The trustee will have a lien on the assets of the trust as security for this indemnification and its compensation earned as trustee. Trust unitholders will not be liable to the trustee for any indemnification. See “Description of the Trust Units — Liability of Trust Unitholders.” The trustee must ensure that all contractual liabilities of the trust are limited to the assets of the trust and the trustee will be liable for its failure to do so.

The trustee may consult with counsel, accountants, tax advisors, geologists, engineers and other parties the trustee believes to be qualified as experts on the matters for which advice is sought. The trustee will be protected for any action it takes in good faith reliance upon the opinion of the expert.

Except as expressly set forth in the trust agreement, neither Enduro Sponsor, the trustee, the Delaware trustee nor the other indemnified parties have any duties or liabilities, including fiduciary duties, to the trust or any trust unitholder. The provisions of the trust agreement, to the extent they restrict, eliminate or otherwise modify the duties and liabilities, including fiduciary duties of these persons otherwise existing at law or in equity, are agreed by the trust unitholders to replace such other duties and liabilities of these persons.

Duration of the Trust; Sale of the Net Profits Interest

The trust will dissolve upon the earliest to occur of the following:


	•	the trust, upon the approval of the holders of at least 75% of the outstanding trust units, sells the Net Profits Interest;

	•	the annual cash available for distribution to the trust is less than $2 million for each of any two consecutive years;

	•	the holders of at least 75% of the outstanding trust units vote in favor of dissolution; or

	•	the trust is judicially dissolved.

The trustee would then sell all of the trust’s assets, either by private sale or public auction, and, after payment or the making of reasonable provision for payment of all liabilities of the trust, distribute the net proceeds of the sale to the trust unitholders.

Dispute Resolution

Any dispute, controversy or claim that may arise between Enduro Sponsor and the trustee relating to the trust will be submitted to binding arbitration before a tribunal of three arbitrators.

Compensation of the Trustee and the Delaware Trustee

The trustee’s and the Delaware trustee’s compensation will be paid out of the trust’s assets. See “— Fees and Expenses.”

Miscellaneous

The principal offices of the trustee are located at 919 Congress Avenue, Suite 500, Austin, Texas 78701, and its telephone number is 1-800-852-1422.

The Delaware trustee and the trustee may resign at any time or be removed with or without cause at any time by the affirmative vote of not less than a majority of the trust units present in person or by proxy at a meeting of such holders where a quorum is present. Any successor must be a bank or trust company meeting certain requirements including having combined capital, surplus and undivided profits of at least $20,000,000, in the case of the Delaware trustee, and $100,000,000, in the case of the trustee.

DESCRIPTION OF THE TRUST UNITS

Each trust unit is a unit of beneficial interest in the trust assets and is entitled to receive cash distributions from the trust on a pro rata basis. Each trust unitholder has the same rights regarding each of his trust units as every other trust unitholder has regarding his units. The trust units will be in book-entry form only and will not be represented by certificates. The trust will have [ ] trust units outstanding upon completion of this offering.

Distributions and Income Computations

Each month, the trustee will determine the amount of funds available for distribution to the trust unitholders. Available funds are the excess cash, if any, received by the trust from the Net Profits Interest and other sources (such as interest earned on any amounts reserved by the trustee) that month, over the trust’s liabilities for that month. Available funds will be reduced by any cash the trustee decides to hold as a reserve against future liabilities. The holders of trust units as of the applicable record date (generally the 15th day of each calendar month) are entitled to monthly distributions payable on or before the 10th business day after the record date. The first distribution to trust unitholders purchasing trust units in this offering will be made on or about October 28, 2011 to trust unitholders owning trust units on or about October 14, 2011.

Unless otherwise advised by counsel or the IRS, the trustee will treat the income and expenses of the trust for each month as belonging to the trust unitholders of record on the monthly record date. Trust unitholders generally will recognize income and expenses for tax purposes in the month the trust receives or pays those amounts, rather than in the month the trust distributes the cash to which such income or expenses (as applicable) relate. Minor variances may occur. For example, the trustee could establish a reserve in one month that would not result in a tax deduction until a later month. See “Federal Income Tax Consequences.”

Transfer of Trust Units

Trust unitholders may transfer their trust units in accordance with the trust agreement. The trustee will not require either the transferor or transferee to pay a service charge for any transfer of a trust unit. The trustee may require payment of any tax or other governmental charge imposed for a transfer. The trustee may treat the owner of any trust unit as shown by its records as the owner of the trust unit. The trustee will not be considered to know about any claim or demand on a trust unit by any party except the record owner. A person who acquires a trust unit after any monthly record date will not be entitled to the distribution relating to that monthly record date. Delaware law will govern all matters affecting the title, ownership or transfer of trust units.

Periodic Reports

The trustee will file all required trust federal and state income tax and information returns. The trustee will prepare and mail to trust unitholders annual reports that trust unitholders need to correctly report their share of the income and deductions of the trust. The trustee will also cause to be prepared and filed reports required to be filed under the Exchange Act and by the rules of any securities exchange or quotation system on which the trust units are listed or admitted to trading, and will also cause the trust to comply with all of the provisions of the Sarbanes-Oxley Act, including but not limited to, establishing, evaluating and maintaining a system of internal control over financial reporting in compliance with the requirements of Section 404 thereof.

Each trust unitholder and his representatives may examine, for any proper purpose, during reasonable business hours, the records of the trust and the trustee, subject to such restrictions as are set forth in the trust agreement.

Liability of Trust Unitholders

Under the Delaware Statutory Trust Act, trust unitholders will be entitled to the same limitation of personal liability extended to stockholders of private corporations for profit under the General Corporation Law of the State of Delaware. No assurance can be given, however, that the courts in jurisdictions outside of Delaware will give effect to such limitation.

Voting Rights of Trust Unitholders

The trustee or trust unitholders owning at least 10% of the outstanding trust units may call meetings of trust unitholders. The trust will be responsible for all costs associated with calling a meeting of trust unitholders unless such meeting is called by the trust unitholders, in which case the trust unitholders will be responsible for all costs associated with calling such meeting of trust unitholders. Meetings must be held in such location as is designated by the trustee in the notice of such meeting. The trustee must send notice of the time and place of the meeting and the matters to be acted upon to all of the trust unitholders at least 20 days and not more than 60 days before the meeting. Trust unitholders representing a majority of trust units outstanding must be present or represented to have a quorum. Each trust unitholder is entitled to one vote for each trust unit owned. Abstentions and broker non-votes shall not be deemed to be a vote cast.

Unless otherwise required by the trust agreement, a matter may be approved or disapproved by the affirmative vote of a majority of the trust units present in person or by proxy at a meeting where there is a quorum. This is true, even if a majority of the total trust units did not approve it. The affirmative vote of the holders of at least 75% of the outstanding trust units is required to:


	•	dissolve the trust;

	•	amend the trust agreement (except with respect to certain matters that do not adversely affect the rights of trust unitholders in any material respect); or

	•	approve the sale of all or any material part of the assets of the trust (including the sale of the Net Profits Interest).

In addition, certain amendments to the trust agreement may be made by the trustee without approval of the trust unitholders. See “Description of the Trust Agreement — Creation and Organization of the Trust; Amendments.” The trustee must consent before all or any part of the trust assets can be sold except in connection with the dissolution of the trust or limited sales directed by Enduro Sponsor in conjunction with its sale of the Underlying Properties.

Comparison of Trust Units and Common Stock

Trust unitholders have more limited voting rights than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of trust unitholders or for annual or other periodic re-election of the trustee.

You should also be aware of the following ways in which an investment in trust units is different from an investment in common stock of a corporation.


	Trust Units	Common Stock

Voting	The trust agreement provides voting rights to trust unitholders to remove and replace the trustee and to approve or disapprove amendments to the trust agreement and certain major trust transactions.	Unless otherwise provided in the certificate of incorporation, the corporate statutes provide voting rights to stockholders to elect directors and to approve or disapprove amendments to the certificate of incorporation and certain major corporate transactions.

Income Tax	The trust is not subject to income tax; trust unitholders are subject to income tax on their pro rata share of trust income, gain, loss and deduction.	Corporations are taxed on their income and their stockholders are taxed on dividends.

Distributions	Substantially all of the cash receipts of the trust is required to be distributed to trust unitholders.	Unless otherwise provided in the certificate of incorporation, stockholders are entitled to receive dividends solely at the discretion of the board of directors.

Business and Assets	The business of the trust is limited to specific assets with a finite economic life.	Unless otherwise provided in the certificate of incorporation, a corporation conducts an active business for an unlimited term and can reinvest its earnings and raise additional capital to expand.

Fiduciary Duties	The trustee shall not be liable to the trust unitholders for any of its acts or omissions absent its own fraud, gross negligence or willful misconduct.	Officers and directors have a fiduciary duty of loyalty to the corporation and its stockholders and a duty to exercise due care in the management and administration of a corporation’s affairs.

TRUST UNITS ELIGIBLE FOR FUTURE SALE

General

Prior to this offering, there has been no public market for the trust units. Sales of substantial amounts of the trust units in the open market, or the perception that those sales could occur, could adversely affect prevailing market prices.

Upon completion of this offering, there will be outstanding [ ] trust units. All of the trust units sold in this offering, or [ ] trust units if the underwriters exercise their option to purchase additional trust units in full, will be freely tradable without restriction under the Securities Act of 1933, as amended (the “Securities Act”). All of the trust units outstanding other than the trust units sold in this offering (a total of [ ] trust units, or [ ]trust units if the underwriters exercise their option to purchase additional trust units in full) will be “restricted securities” within the meaning of Rule 144 under the Securities Act and may not be sold other than through registration under the Securities Act or pursuant to an exemption from registration, subject to the restrictions on transfer contained in the lock-up agreements described below and in “Underwriting (Conflicts of Interest).”

Lock-Up Agreements

In connection with this offering, Enduro Sponsor, and Enduro Sponsor’s officers or managers participating in the directed unit program, have agreed, for a period of 180 days after the date of this prospectus, not to offer, sell, contract to sell or otherwise dispose of or transfer any trust units or any securities convertible into or exchangeable for trust units without the prior written consent of Barclays Capital Inc., subject to specified exceptions. See “Underwriting (Conflicts of Interest)” for a description of these lock-up arrangements. Upon the expiration of these lock-up agreements, [ ] trust units, or [ ] trust units if the underwriters exercise their option to purchase additional trust units in full, will be eligible for sale in the public market under Rule 144 of the Securities Act, subject to volume limitations and other restrictions contained in Rule 144, or through registration under the Securities Act.

Rule 144

The trust units sold in the offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any trust units owned by an “affiliate” of the trust, including those held by Enduro Sponsor, may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:


	•	1.0% of the total number of the securities outstanding, or

	•	the average weekly reported trading volume of the trust units for the four calendar weeks prior to the sale.

Sales under Rule 144 are also subject to specific manners of sale provisions, holding period requirements, notice requirements and the availability of current public information about the trust. A person who is not deemed to have been an affiliate of Enduro Sponsor or the trust at any time during the three months preceding a sale, and who has beneficially owned his trust units for at least six months (provided the trust is in compliance with the current public information requirement) or one year (regardless of whether the trust is in compliance with the current public information requirement), would be entitled to sell trust units under Rule 144 without regard to the rule’s public information requirements, volume limitations, manner of sale provisions and notice requirements.

Registration Rights

The trust intends to enter into a registration rights agreement with Enduro Sponsor in connection with Enduro Sponsor’s contribution to the trust of the Net Profits Interest. In the registration rights agreement, the trust will agree, for the benefit of Enduro Sponsor and any transferee of Enduro Sponsor’s trust units (the “holders”), to register the trust units they hold. Specifically, the trust will agree:


	•	subject to the restrictions described above under “— Lock-Up Agreements” and under “Underwriting (Conflicts of Interest) — Lock-Up Agreements,” to use its reasonable best efforts to file a registration statement, including, if so requested, a shelf registration statement, with the SEC as promptly as practicable following receipt of a notice requesting the filing of a registration statement from holders representing a majority of the then outstanding registrable trust units;


	•	to use its commercially reasonable efforts to cause the registration statement or shelf registration statement to be declared effective under the Securities Act as promptly as practicable after the filing thereof; and

	•	to use its commercially reasonable efforts to maintain the effectiveness of the registration statement under the Securities Act for 90 days (or for three years if a shelf registration statement is requested) after the effectiveness thereof or until the trust units covered by the registration statement have been sold pursuant to such registration statement or until all registrable trust units:


	•	have been sold pursuant to Rule 144 under the Securities Act if the transferee thereof does not receive “restricted securities;”

	•	have been sold in a private transaction in which the transferor’s rights under the registration rights agreement are not assigned to the transferee of the trust units; or

	•	become eligible for resale pursuant to Rule 144 (or any similar rule then in effect under the Securities Act).

The holders will have the right to require the trust to file no more than three registration statements in aggregate.

In connection with the preparation and filing of any registration statement, Enduro Sponsor will bear all costs and expenses incidental to any registration statement, excluding certain internal expenses of the trust, which will be borne by the trust. Any underwriting discounts and commissions will be borne by the seller of the trust units.

FEDERAL INCOME TAX CONSEQUENCES

U.S. Federal Income Tax Consequences

This section is a summary of the material U.S. federal income tax considerations that may be relevant to prospective trust unitholders and, unless otherwise noted in the following discussion, is the opinion of Latham & Watkins LLP, counsel to the trust, insofar as it relates to legal conclusions with respect to matters of U.S. federal income tax law. This section is based upon current provisions of the Internal Revenue Code of 1986, as amended (the “Code”), existing and proposed Treasury regulations promulgated under the Code (the “Treasury Regulations”) and current administrative rulings and court decisions, all of which are subject to change or different interpretation at any time, possibly with retroactive effect. Later changes in these authorities may cause the U.S. federal income tax consequences to vary substantially from the consequences described below.

The following discussion does not comment on all federal income tax matters affecting the trust or trust unitholders. The following discussion is limited to trust unitholders who hold the trust units as “capital assets” (generally, property held for investment). All references to “trust unitholders” (including U.S. trust unitholders and non-U.S. trust unitholders) are to beneficial owners of the trust units. This summary does not address the effect of the U.S. federal estate or gift tax laws or the tax considerations arising under the law of any state (except as provided in the limited summary below under “State Tax Considerations”), local or non-U.S. jurisdiction. Moreover, the discussion has only limited application to trust unitholders subject to special tax treatment such as, without limitation:


	•	banks, insurance companies or other financial institutions;

	•	trust unitholders subject to the alternative minimum tax;

	•	tax-exempt organizations;

	•	dealers in securities or commodities;

	•	regulated investment companies;

	•	real estate investment trusts;

	•	traders in securities that elect to use a mark-to-market method of accounting for their securities holdings;

	•	non-U.S. trust unitholders (as defined below) that are “controlled foreign corporations” or “passive foreign investment companies”;

	•	persons that are S-corporations, partnerships or other pass-through entities;

	•	persons that own their interest in the trust units through S-corporations, partnerships or other pass-through entities;

	•	persons that at any time own more than 5% of the aggregate fair market value of the trust units;

	•	expatriates and certain former citizens or long-term residents of the United States;

	•	U.S. trust unitholders (as defined below) whose functional currency is not the U.S. dollar;

	•	persons who hold the trust units as a position in a hedging transaction, “straddle,” “conversion transaction” or other risk reduction transaction; or

	•	persons deemed to sell the trust units under the constructive sale provisions of the Code.

Prospective investors are urged to consult their tax advisors as to the particular tax consequences to them of the ownership and disposition of an investment in trust units, including the applicability of any U.S. federal income, federal estate or gift tax, state, local and foreign tax laws, changes in applicable tax laws and any pending or proposed legislation.

As used herein, the term “U.S. trust unitholder” means a beneficial owner of trust units that for U.S. federal income tax purposes is:


	•	an individual who is a citizen of the United States or who is a resident of the United States for U.S. federal income tax purposes,

	•	a corporation, or an entity treated as a corporation for U.S. federal income tax purposes, created or organized in or under the laws of the United States, a state thereof or the District of Columbia,

	•	an estate the income of which is subject to U.S. federal income taxation regardless of its source, or

	•	a trust if it is subject to the primary supervision of a U.S. court and the control of one or more United States persons (as defined for U.S. federal income tax purposes) or that has a valid election in effect under applicable U.S. Treasury regulations to be treated as a United States person.

The term “non-U.S. trust unitholder” means any beneficial owner of a trust unit that is an individual, corporation, estate or trust and that is not a U.S. trust unitholder.

If a partnership (including for this purpose any entity or arrangement treated as a partnership for U.S. federal income tax purposes) is a beneficial owner of trust units, the tax treatment of a partner in the partnership will depend upon the status of the partner and the activities of the partnership. A trust unitholder that is a partnership, and the partners in such partnership, should consult their own tax advisors about the U.S. federal income tax consequences of purchasing, owning and disposing of trust units.

Classification and Taxation of the Trust

In the opinion of Latham & Watkins LLP, for U.S. federal income tax purposes, the trust will be treated as a grantor trust and not as an unincorporated business entity. As a grantor trust, the trust will not be subject to tax at the trust level. Rather, the grantors, who in this case are the trust unitholders, will be considered, for U.S. federal income tax purposes, to own and receive the trust’s assets and income and will be directly taxable thereon as though no trust were in existence.

No ruling has been or will be requested from the IRS with respect to the U.S. federal income tax treatment of the trust, including a ruling as to the status of the trust as a grantor trust or as a partnership for U.S. federal income tax purposes. Thus, no assurance can be provided that the opinions and statements set forth in this discussion of U.S. federal income tax consequences would be sustained by a court if contested by the IRS.

The remainder of the discussion below is based on Latham & Watkins LLP’s opinion that the trust will be classified as a grantor trust for U.S. federal income tax purposes.

Reporting Requirements for Widely-Held Fixed Investment Trusts

Under Treasury Regulations, the trust is classified as a widely-held fixed investment trust. Those Treasury Regulations require the sharing of tax information among trustees and intermediaries that hold a trust interest on behalf of or for the account of a beneficial owner or any representative or agent of a trust interest holder of fixed investment trusts that are classified as widely-held fixed investment trusts. These reporting requirements provide for the dissemination of trust tax information by the trustee to intermediaries who are ultimately responsible for reporting the investor-specific information through Form 1099 to the investors and the IRS. Every trustee or intermediary that is required to file a Form 1099 for a trust unitholder must furnish a written tax information statement that is in support of the amounts as reported on the applicable Form 1099 to the trust unitholder. Any generic tax information provided by the trustee of the trust is intended to be used only to assist trust unitholders in the preparation of their federal and state income tax returns.

Direct Taxation of Trust Unitholders

Because the trust will be treated as a grantor trust for U.S. federal income tax purposes, trust unitholders will be treated for such purposes as owning a direct interest in the assets of the trust, and each trust unitholder will be taxed directly on his pro rata share of the income and gain attributable to the assets of the trust and will be entitled to claim his pro rata share of the deductions and expenses attributable to the assets of the trust (subject to certain limitations discussed below). Information returns will be filed as required by the widely held fixed investment trust rules, reporting to the trust unitholders all items of income, gain, loss, deduction and credit, which will be allocated based on record ownership on the monthly record dates and must be included in the tax returns of the trust unitholders. Income, gain, loss, deduction and credits attributable to the assets of the trust will be taken into account by trust unitholders consistent with their method of accounting and without regard to the taxable year or accounting method employed by the trust.

Following the end of each month, the trustee will determine the amount of funds available as of the end of such month for distribution to the trust unitholders and will make distributions of available funds, if any, to the trust unitholders on or before the 10th business day after the record date, which will generally be on or about the 15th day of each calendar month. In certain circumstances, however, a trust unitholder will not receive a distribution of cash attributable to the income from a month. For example, if the trustee establishes a reserve or borrows money to satisfy liabilities of the trust, income associated with the cash used to establish that reserve or to repay that loan must be reported by the trust unitholder, even though that cash is not distributed to him.

As described above, the trust will allocate items of income, gain, loss, deductions and credits to trust unitholders based on record ownership on the monthly record dates. It is possible that the IRS could disagree with this allocation method and could assert that income and deductions of the trust should be determined and allocated on a daily or prorated basis, which could require adjustments to the tax returns of the unitholders affected by the issue and result in an increase in the administrative expense of the trust in subsequent periods.

The trust estimates that a purchaser of trust units in this offering who owns such trust units through the record date for distributions for the period ending December 31, 2013, will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be approximately [ ]% of the cash distributed with respect to that period. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond the trust’s control. Further, the estimates are based on current tax law and tax reporting positions that the trust will adopt and with which the IRS could disagree. Accordingly, the trust cannot assure unitholders that these estimates will prove to be correct. The actual percentage of distributions that will correspond to taxable income could be higher or lower than expected, and any differences could be material and could materially affect the value of the trust units.

Tax Classification of the Net Profits Interest

For U.S. federal income tax purposes, the Net Profits Interest attributable to proved developed reserves (“PDP NPI”) or proved undeveloped reserves (“PUD NPI”) will have the tax characteristics of mineral royalty interests to the extent, at the time of its creation, such PDP NPI or PUD NPI is reasonably expected to have an economic life that corresponds substantially to the economic life of the mineral property or properties burdened thereby. Payments out of production that are received in respect of a mineral interest that constitutes a royalty interest for U.S. federal income tax purposes are taxable under current law as ordinary income subject to an allowance for cost or percentage depletion in respect of such income.

Based on the reserve report and representations made by Enduro Sponsor regarding the expected economic life of the Underlying Properties and the expected duration of the Net Profits Interest, the PDP NPI will and the PUD NPI should be treated as continuing, nonoperating economic interests in the nature of royalties payable out of production from the mineral interests they burden.

Consistent with the foregoing, Enduro Sponsor and the trust intend to treat the Net Profits Interest as a mineral royalty interest for U.S. federal income tax purposes. The remainder of this discussion assumes that the Net Profits Interest is treated as a mineral royalty interest. No assurance can be given that the IRS will not assert that such interest should be treated differently. Any such different treatment could affect the amount, timing and character of income, gain or loss in respect of an investment in trust units. Please read “— Tax Consequences to U.S. Trust Unitholders.”

The portion of the purchase price of the trust units attributable to the right to receive a distribution based on production from the Underlying Properties for the period commencing May 1, 2011, and ending on [ ] will be treated as a tax-free return of capital when such distribution is received.

Tax Consequences to U.S. Trust Unitholders

Royalty Income and Depletion

Consistent with the discussion above in “— Tax Classification of the Net Profits Interest,” the payments out of production that are received by the trust in respect of the Net Profits Interest constitute ordinary income received in respect of a mineral royalty interest. Trust unitholders should be entitled to deductions for the greater of either cost depletion or (if allowable) percentage depletion with respect to such income. Although the Code requires each trust unitholder to compute his own depletion allowance and maintain records of his share of the adjusted tax basis of the underlying royalty interest for depletion and other purposes, the trust intends to furnish each of the trust unitholders with information relating to this computation for U.S. federal income tax purposes. Each trust unitholder, however, remains responsible for calculating his own depletion allowance and maintaining records of his share of the adjusted tax basis of the underlying property for depletion and other purposes.

Percentage depletion is generally available with respect to trust unitholders who qualify under the independent producer exemption contained in section 613A(c) of the Code. For this purpose, an independent producer is a person not directly or indirectly involved in the retail sale of oil, natural gas or derivative products or the operation of a major refinery. In general, percentage depletion is calculated as an amount equal to 15% (and, in the case of marginal production, potentially a higher percentage) of the trust unitholder’s gross income from the depletable property for the taxable year. The percentage depletion deduction with respect to any property is limited to 100% of the taxable income of the trust unitholder from the property for each taxable year, computed without the depletion allowance or certain loss carrybacks. A trust unitholder that qualifies as an independent producer may deduct percentage depletion only to the extent the trust unitholder’s average daily production of domestic crude oil, or the natural gas equivalent, does not exceed 1,000 barrels. This depletable amount may be allocated between oil and natural gas production, with 6,000 cubic feet of domestic natural gas production regarded as equivalent to one barrel of crude oil. The 1,000 barrel limitation must be allocated among the independent producer and controlled or related persons and family members in proportion to the respective production by such persons during the period in question.

In addition to the foregoing limitations, the percentage depletion deduction otherwise available is limited to 65% of a trust unitholder’s total taxable income from all sources for the year, computed without the depletion allowance and certain loss carrybacks. Any percentage depletion deduction disallowed because of the 65% limitation may be deducted in the following taxable year if the percentage depletion deduction for such year plus the deduction carryover does not exceed 65% of the trust unitholder’s total taxable income for that year. The carryover period resulting from the 65% net income limitation is unlimited.

Unlike cost depletion, percentage depletion is not limited to the adjusted tax basis of the property, although, like cost depletion, it reduces the adjusted tax basis, but not below zero.

In addition to the limitations on percentage depletion discussed above, on February 14, 2011, the White House released President Obama’s budget proposal for the fiscal year 2012 (the “2012 Budget”). The 2012 Budget proposes to eliminate certain tax preferences applicable to taxpayers engaged in the exploration and production of natural resources. Specifically, the 2012 Budget proposes to repeal the deduction for percentage depletion with respect to oil and natural gas wells, in which case only cost depletion would be available. It is uncertain whether this or any other legislative proposals will ever be enacted and, if so, when it would become effective.

Trust unitholders that do not qualify under the independent producer exemption are generally restricted to depletion deductions based on cost depletion. Cost depletion deductions are calculated by (i) dividing the trust unitholder’s allocable share of the adjusted tax basis in the underlying mineral property by the number of mineral units (barrels of oil and thousand cubic feet, or Mcf, of natural gas) remaining as of the beginning of the taxable year and (ii) multiplying the result by the number of mineral units sold within the taxable year. The total amount of deductions based on cost depletion cannot exceed the trust unitholder’s share of the total adjusted tax basis in the property.

The foregoing discussion of depletion deductions does not purport to be a complete analysis of the complex legislation and Treasury Regulations relating to the availability and calculation of depletion deductions by the trust unitholders. Further, because depletion is required to be computed separately by each trust unitholder and not by the trust, no assurance can be given, and counsel is unable to express any opinion, with respect to the availability or extent of percentage depletion deductions to the trust unitholders for any taxable year. The trust encourages each prospective trust unitholder to consult his tax advisor to determine whether percentage depletion would be available to him.

Tax Rates

Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 35% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than 12 months) of individuals is 15%. However, absent new legislation extending the current rates, beginning January 1, 2013, the highest marginal U.S. federal income tax rate applicable to ordinary income and long-term capital gains of individuals will increase to 39.6% and 20%, respectively. Moreover, these rates are subject to change by new legislation at any time.

The recently enacted Health Care and Education Reconciliation Act of 2010 will impose a 3.8% Medicare tax on certain investment income earned by individuals and certain estates and trusts for taxable years beginning after December 31, 2012. For these purposes, investment income would generally include certain income derived from investments such as the trust units and gain realized by a trust unitholder from a sale of trust units. In the case of an individual, the tax will be imposed on the lesser of (i) the trust unitholder’s net income from all investments and (ii) the amount by which the trust unitholder’s modified adjusted gross income exceeds $250,000 (if the trust unitholder is married and filing jointly or a surviving spouse), $125,000 (if the trust unitholder is married and filing separately) or $200,000 (in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (1) undistributed net investment income, or (2) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

Non-Passive Activity Income and Loss

The income and losses of the trust will not be taken into account in computing the passive activity losses and income under Code section 469 for a trust unitholder who acquires and holds trust units as an investment.

Disposition of Trust Units

For U.S. federal income tax purposes, a sale of trust units will be treated as a sale by the U.S. trust unitholder of his interest in the assets of the trust. Generally, a U.S. trust unitholder will recognize gain or loss on a sale or exchange of trust units equal to the difference between the amount realized and the U.S. trust unitholder’s adjusted tax basis for the trust units sold. A U.S. trust unitholder’s adjusted tax basis in his trust units will be equal to the U.S. trust unitholder’s original purchase price for the trust units, reduced by deductions for depletion claimed by the trust unitholder, but not below zero. Except to the extent of the depletion recapture amount explained below, gain or loss on the sale of trust units by a trust unitholder who is an individual will generally be capital gain, and will be long-term capital gain, which is generally subject to tax at preferential rates, if the trust units have been held for more than twelve months. The deductibility of capital losses is limited. Upon the sale or other taxable disposition of his trust units, a trust unitholder will be treated as having sold his share of the Net Profits Interest and must treat as ordinary income his depletion recapture amount, which is an amount equal to the lesser of the gain on such sale or other taxable disposition or the sum of the prior depletion deductions taken with respect to the trust units, but not in excess of the initial tax basis of the trust units. The IRS could take the position that a portion of the sales proceeds is ordinary income to the extent of any accrued income at the time of the sale that was allocable to the trust units sold even though the income is not distributed to the selling trust unitholder.

Trust Administrative Expenses

Expenses of the trust will include administrative expenses of the trustee. Certain miscellaneous itemized deductions may be subject to general limitations on deductibility. Under these rules, administrative expenses attributable to the trust units are miscellaneous itemized deductions that generally will have to be aggregated with an individual unitholder’s other miscellaneous itemized deductions to determine the excess over 2% of adjusted gross income. It is anticipated that the amount of such administrative expenses will not be significant in relation to the trust’s income.

Backup Withholding

Distributions of trust income generally will not be subject to backup withholding unless the trust unitholder is an individual or other noncorporate entity and fails to comply with specified reporting procedures.

Tax Treatment Upon Sale of the Net Profits Interest

The sale of the Net Profits Interest by the trust at or shortly after the date of dissolution of the trust will generally give rise to long-term capital gain or loss to the trust unitholders for U.S. federal income tax purposes, except that any gain will be taxed at ordinary income rates to the extent of depletion deductions that reduced the trust unitholder’s adjusted basis in the Net Profits Interest.

Tax Consequences to Non-U.S. Trust Unitholders

The following is a summary of certain material U.S. federal income tax consequences that will apply to you if you are a non-U.S. trust unitholder. Non-U.S. trust unitholders should consult their independent tax advisors to determine the U.S. federal, state, local and foreign tax consequences that may be relevant to them.

Payments with Respect to the Trust Units

A non-U.S. trust unitholder will be subject to federal withholding tax on his share of gross royalty income from the Net Profits Interest. The withholding tax will apply at a 30% rate, or lower applicable treaty rate, to the gross royalty income received by the non-U.S. trust unitholder without the benefit of any deductions.

Sale or Exchange of Trust Units

The Net Profits Interest will be treated as a “United States real property interest” for U.S. federal income tax purposes. However, as long as the trust units are traded on an established securities exchange, gain realized on the sale or other taxable disposition of a trust unit by a non-U.S. trust unitholder will be subject to federal income tax only if:


	•	the gain is otherwise effectively connected with business conducted by the non-U.S. trust unitholder in the United States (and, in the case of an applicable tax treaty, is attributable to a permanent establishment or fixed base maintained in the United States by the non-U.S. trust unitholder);

	•	the non-U.S. trust unitholder is an individual who is present in the United States for at least 183 days in the year of the sale or other taxable disposition; or

	•	the non-U.S. trust unitholder owns currently, or owned at certain earlier times, directly, or by applying certain attribution rules, more than 5% of the trust units.

Gain realized by a non-U.S. trust unitholder upon the sale or other taxable disposition by the trust of all or any part of the Net Profits Interest would be subject to federal income tax, and distributions to the non-U.S. trust unitholder will be subject to withholding of U.S. tax (currently at the rate of 35%) to the extent distributions are attributable to such gains.

Tax Consequences to Tax Exempt Organizations

Employee benefit plans and most other organizations exempt from U.S. federal income tax including IRAs and other retirement plans are subject to U.S. federal income tax on unrelated business taxable income. Because the trust’s income is not expected to be unrelated business taxable income, such a tax-exempt organization is not expected to be taxed on income generated by ownership of trust units so long as neither the property held by the trust nor the trust units are treated as debt-financed property within the meaning of Section 514(b) of the Code. In general, trust property would be debt-financed if the trust incurs debt to acquire the property or otherwise incurs or maintains a debt that would not have been incurred or maintained if the property had not been acquired and a trust unit would be debt-financed if the trust unitholder incurs debt to acquire the trust unit or otherwise incurs or maintains a debt that would not have been incurred or maintained if the trust unit had not been acquired.

PROSPECTIVE INVESTORS IN TRUST UNITS ARE STRONGLY ENCOURAGED TO CONSULT THEIR TAX ADVISORS WITH RESPECT TO THE TAX CONSEQUENCES TO THEM OF THE PURCHASE, OWNERSHIP AND DISPOSITION OF THE TRUST UNITS IN LIGHT OF THEIR OWN PARTICULAR CIRCUMSTANCES, INCLUDING THE TAX CONSEQUENCES UNDER STATE, LOCAL, FOREIGN AND OTHER TAX LAWS AND THE POSSIBLE EFFECTS OF CHANGES IN UNITED STATES FEDERAL OR OTHER TAX LAWS.

STATE TAX CONSIDERATIONS

The following is a brief summary of certain information regarding state income taxes and other state tax matters affecting individuals who are trust unitholders. No opinion of counsel has been requested or received with respect to the state tax consequences of an investment in trust units. The trust is not providing any tax advice with respect to the state tax consequences applicable to any particular purchaser of trust units. Accordingly, prospective investors are urged to consult their tax advisors with respect to these matters.

The trust will own net profits interests burdening specified oil and natural gas properties located in the states of Louisiana, New Mexico and Texas. Louisiana and New Mexico currently impose a personal income tax on individuals, but Texas currently does not.

An individual who is a resident of Louisiana or New Mexico will generally be subject to income tax in his or her state of residence on that individual’s entire share of the trust’s income.

New Mexico imposes income taxes upon residents and nonresidents. In the case of nonresidents, income derived from tangible property within the state is subject to tax. The income tax laws of New Mexico are based on federal income tax laws. Thus, assuming the trust is taxed as a grantor trust for federal income tax purposes, the trust unitholders will be subject to New Mexico income tax on their share of income from New Mexico net profits interests. The withholding requirements with respect to trust units under New Mexico law are uncertain; the trust has taken the position that the trust is not required to withhold income tax in New Mexico on distributions made to an individual resident or nonresident trust unitholder.

Louisiana also imposes income taxes upon residents and nonresidents. In the case of nonresidents, income derived from property within the state is subject to tax. The income tax laws of Louisiana are based on federal income tax laws. Assuming the trust is taxed as a grantor trust for federal income tax purposes, the trust unitholders will be subject to Louisiana income tax on their share of income from Louisiana net profits interests. The trust should not be required to withhold income tax due in Louisiana on distributions made to an individual resident or nonresident trust unitholder.

ERISA CONSIDERATIONS

The Employee Retirement Income Security Act of 1974, as amended (“ERISA”), regulates pension, profit-sharing and other employee benefit plans to which it applies. ERISA also contains standards for persons who are fiduciaries of those plans. In addition, the Code provides similar requirements and standards which are applicable to qualified plans, which include these types of plans, and to individual retirement accounts, whether or not subject to ERISA.

A fiduciary of an employee benefit plan should carefully consider fiduciary standards under ERISA regarding the plan’s particular circumstances before authorizing an investment in trust units. A fiduciary should consider:


	•	whether the investment satisfies the prudence requirements of Section 404(a)(1)(B) of ERISA;

	•	whether the investment satisfies the diversification requirements of Section 404(a)(1)(C) of ERISA; and

	•	whether the investment is in accordance with the documents and instruments governing the plan as required by Section 404(a)(1)(D) of ERISA.

A fiduciary should also consider whether an investment in trust units might result in direct or indirect nonexempt prohibited transactions under Section 406 of ERISA and Section 4975 of the Code. In deciding whether an investment involves a prohibited transaction, a fiduciary must determine whether there are plan assets in the transaction. The Department of Labor has published final regulations concerning whether or not an employee benefit plan’s assets would be deemed to include an interest in the underlying assets of an entity for purposes of the reporting, disclosure and fiduciary responsibility provisions of ERISA and analogous provisions of the Code. These regulations provide that the underlying assets of an entity will not be considered “plan assets” if the equity interests in the entity are a publicly offered security. Enduro Sponsor expects that at the time of the sale of the trust units in this offering, they will be publicly offered securities. Fiduciaries, however, will need to determine whether the acquisition of trust units is a nonexempt prohibited transaction under the general requirements of ERISA Section 406 and Section 4975 of the Code.

The prohibited transaction rules are complex, and persons involved in prohibited transactions are subject to penalties. For that reason, potential employee benefit plan investors should consult with their counsel to determine the consequences under ERISA and the Code of their acquisition and ownership of trust units.

SELLING TRUST UNITHOLDER

Immediately prior to the closing of the offering made hereby, Enduro Sponsor will convey to the trust the Net Profits Interest in exchange for [ ] trust units. Of those trust units, [ ] are being offered hereby and [ ] are subject to purchase by the underwriters pursuant to their 30-day option to purchase additional trust units. Enduro Sponsor has agreed not to sell any of such trust units for a period of 180 days after the date of this prospectus without the prior written consent of Barclays Capital Inc., acting as representative of the several underwriters. See “Underwriting (Conflicts of Interest).” Enduro Sponsor is deemed to be an underwriter with respect to the trust units offered hereby.

The following table provides information regarding the selling trust unitholder’s ownership of the trust units.

Ownership of Trust

Number of

Ownership of Trust Units After

Units Before Offering

Trust Units

Offering

Selling Trust Unitholder

Number

Percentage

Being Offered

Number

Percentage

Enduro Sponsor

[ ]

100.0

[

]⁽¹⁾

[ ]


⁽¹⁾		Includes [ ] trust units subject to purchase by the underwriters pursuant to their 30-day option to purchase additional units.

Prior to this offering, there has been no public market for the trust units. Therefore, if Enduro Sponsor disposes of all or a portion of the trust units it has acquired, the effect of such disposal on future market prices, if any, of market sales of such remaining trust units or the availability of trust units for sale cannot be predicted. Nevertheless, sales of substantial amounts of trust units in the public market could adversely affect future market prices.

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UNDERWRITING (CONFLICTS OF INTEREST)

Barclays Capital Inc. is acting as the representative of the underwriters of this offering. Under the terms of an underwriting agreement, which will be filed as an exhibit to the registration statement, each of the underwriters named below has severally agreed to purchase from Enduro Sponsor the respective number of trust units shown opposite its name below:


	Number of
Underwriters	Trust Units

Barclays Capital Inc.		[ ]
Citigroup Global Markets Inc.		[ ]
Goldman, Sachs & Co.		[ ]
RBC Capital Markets, LLC		[ ]
Wells Fargo Securities, LLC		[ ]

Total		[ ]

The underwriting agreement provides that the underwriters’ obligation to purchase trust units depends on the satisfaction of the conditions contained in the underwriting agreement including:


	•	the obligation to purchase all of the trust units offered hereby (other than those trust units covered by their option to purchase additional trust units as described below), if any of the trust units are purchased;

	•	the representations and warranties made by the trust and Enduro Sponsor to the underwriters are true;

	•	there is no material change in the business of the trust or Enduro Sponsor or the financial markets; and

	•	the trust and Enduro Sponsor deliver customary closing documents to the underwriters.

Enduro Sponsor is deemed to be an underwriter with respect to the trust units offered hereby.

Commissions and Expenses

The following table summarizes the underwriting discounts and commissions Enduro Sponsor will pay to the underwriters. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional trust units. The underwriting fee is the difference between the initial price to the public and the amount the underwriters pay to Enduro Sponsor for the trust units.


	No Exercise	Full Exercise

Per trust unit
Total

The representative of the underwriters has advised Enduro Sponsor that the underwriters propose to offer the trust units directly to the public at the public offering price on the cover of this prospectus and to selected dealers, which may include the underwriters, at such offering price less a selling concession not in excess of $ per trust unit. After the offering, the representative may change the offering price and other selling terms.

The offering of the trust units by the underwriters is subject to receipt and acceptance and subject to the underwriters’ right to reject any order in whole or in part.

Enduro Sponsor will pay Barclays Capital Inc. a structuring fee of [ ]% of the gross proceeds of this offering for evaluation, analysis and structuring of the trust.

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The expenses of the offering that are payable by Enduro Sponsor are estimated to be $[ ](excluding underwriting discounts and commissions).

Option to Purchase Additional Trust Units

Enduro Sponsor has granted the underwriters an option exercisable for 30 days after the date of this prospectus, to purchase, from time to time, in whole or in part, up to an aggregate of [ ] trust units at the public offering price less underwriting discounts and commissions. This option may be exercised if the underwriters sell more than [ ] trust units in connection with this offering. To the extent that this option is exercised, each underwriter will be obligated, subject to certain conditions, to purchase its pro rata portion of these additional trust units based on the underwriter’s underwriting commitment in the offering as indicated in the table at the beginning of this Underwriting Section.

Lock-Up Agreements

Enduro Sponsor has agreed that, without the prior written consent of Barclays Capital Inc., they will not directly or indirectly, (1) offer for sale, sell, pledge or otherwise dispose of (or enter into any transaction or device that is designed to, or could be expected to, result in the disposition by any person at any time in the future of) any trust units (including, without limitation, trust units that may be deemed to be beneficially owned by them in accordance with the rules and regulations of the SEC and trust units that may be issued upon exercise of any options or warrants) or securities convertible into or exercisable or exchangeable for trust units, (2) enter into any swap or other derivative transaction that transfers to another, in whole or in part, any of the economic consequences of ownership of the trust units, (3) make any demand for or exercise any right or file or cause to be filed a registration statement, including any amendments thereto, with respect to the registration of any trust units or securities convertible, exercisable or exchangeable into trust units or (4) publicly disclose the intention to do any of the foregoing for a period of 180 days after the date of this prospectus.

The 180-day restricted period described in the preceding paragraph will be extended if:


	•	during the last 17 days of the 180-day restricted period the trust issues an earnings release or material news or a material event relating to the trust occurs; or

	•	prior to the expiration of the 180-day restricted period, the trust announces that it will release earnings results during the 16-day period beginning on the last day of the 180-day period,

in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the announcement of the material news or occurrence of a material event, unless such extension is waived in writing by Barclays Capital Inc.

Barclays Capital Inc., in its sole discretion, may release the trust units and other securities subject to the lock-up agreements described above in whole or in part at any time with or without notice. When determining whether or not to release trust units and other securities from lock-up agreements, Barclays Capital Inc. will consider, among other factors, the holder’s reasons for requesting the release, the number of trust units and other securities for which the release is being requested and market conditions at the time. Barclays Capital Inc. has informed Enduro Sponsor that it does not presently intend to release any trust units or other securities subject to the lock-up agreements.

As described below under “Directed Unit Program,” any participants in the directed unit program will be subject to a 180-day lock up with respect to any trust units sold to them pursuant to that program. This lock up will have similar restrictions and an identical extension provision as the lock-up agreement described above. Any trust units sold in the directed unit program to Enduro Sponsor’s directors or officers will be subject to the lock-up agreement described above.

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Offering Price Determination

Prior to this offering, there has been no public market for the trust units. The initial public offering price will be negotiated between the representative and Enduro Sponsor. In determining the initial public offering price of the trust units, the representative will consider:


	•	estimates of distributions to trust unitholders;


	•	overall quality of the oil and natural gas properties attributable to the Underlying Properties;


	•	the history and prospects for the energy industry;


	•	Enduro Sponsor’s financial information;


	•	the prevailing securities markets at the time of this offering; and


	•	the recent market prices of, and the demand for, publicly traded units of royalty trusts.

Indemnification

The trust and Enduro Sponsor have agreed to indemnify the several underwriters against certain liabilities, including liabilities under the Securities Act and liabilities incurred in connection with the directed unit program referred to below, and to contribute to payments that the underwriters may be required to make for these liabilities.

Directed Unit Program

At Enduro Sponsor’s request, the underwriters have reserved for sale at the initial public offering price up to [ ] trust units offered hereby for officers, managers, employees and certain other persons associated with Enduro Sponsor. The number of trust units available for sale to the general public will be reduced to the extent such persons purchase such reserved trust units. Any reserved trust units not so purchased will be offered by the underwriters to the general public on the same basis as the other trust units offered hereby. Any of Enduro Sponsor’s officers or managers participating in this program shall be prohibited from selling, pledging or assigning any trust units sold to them pursuant to this program for a period of 180 days after the date of this prospectus. This 180-day lock up period will be extended with respect to the trust’s issuance of an earnings release or if a material news or a material event relating to the trust occurs, in the same manner as described above under “— Lock-Up Agreements.”

Stabilization, Short Positions and Penalty Bids

The representative may engage in stabilizing transactions, short sales and purchases to cover positions created by short sales, and penalty bids or purchases for the purpose of pegging, fixing or maintaining the price of the trust units, in accordance with Regulation M under the Exchange Act:


	•	Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

	•	A short position involves a sale by the underwriters of trust units in excess of the number of trust units the underwriters are obligated to purchase in the offering, which creates the syndicate short position. This short position may be either a covered short position or a naked short position. In a covered short position, the number of trust units involved in the sales made by the underwriters in excess of the number of trust units they are obligated to purchase is not greater than the number of trust units that they may purchase by exercising their option to purchase additional trust units. In a naked short position, the number of trust units involved is greater than the number of trust units in their option to purchase additional trust units. The underwriters may close out any short position by either exercising their option to purchase additional trust units and/or

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		purchasing trust units in the open market. In determining the source of trust units to close out the short position, the underwriters will consider, among other things, the price of trust units available for purchase in the open market as compared to the price at which they may purchase trust units through their option to purchase additional trust units. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the trust units in the open market after pricing that could adversely affect investors who purchase in the offering.


	•	Syndicate covering transactions involve purchases of the trust units in the open market after the distribution has been completed in order to cover syndicate short positions.


	•	Penalty bids permit the representative to reclaim a selling concession from a syndicate member when the trust units originally sold by the syndicate member are purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of the trust units or preventing or retarding a decline in the market price of the trust units. As a result, the price of the trust units may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the New York Stock Exchange or otherwise and, if commenced, may be discontinued at any time.

None of the trust, Enduro Sponsor or any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the trust units. In addition, none of the trust, Enduro Sponsor or any of the underwriters make any representation that the representative will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.

Electronic Distribution

A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with Enduro Sponsor to allocate a specific number of trust units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representative on the same basis as other allocations.

Other than the prospectus in electronic format, the information on any underwriter’s or selling group member’s web site and any information contained in any other web site maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by the trust, Enduro Sponsor or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

New York Stock Exchange

The trust intends to apply to list the trust units for quotation on the New York Stock Exchange under the symbol “NDRO.” In connection with that listing, the underwriters have undertaken to sell the minimum number of trust units to the minimum number of beneficial owners necessary to meet the New York Stock Exchange listing requirements.

Discretionary Sales

The underwriters have informed Enduro Sponsor that they do not intend to confirm sales to discretionary accounts that exceed 5% of the total number of trust units offered by them.

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Conflicts of Interest/FINRA Rules

The underwriters and their respective affiliates are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, investment research, principal investment, hedging, financing and brokerage activities. Certain of the underwriters and their respective affiliates have, from time to time, performed, and may in the future perform, various financial advisory and investment banking services for Enduro Sponsor and the trust, for which they received or will receive customary fees and expenses.

Because the Financial Industry Regulatory Authority (“FINRA”) views the trust units offered hereby as interests in a direct participation program, the offering is being made in compliance with Rule 2310 of the FINRA Conduct Rules. In no event will the maximum amount of compensation to be paid to FINRA members in connection with this offering exceed 10% of the offering proceeds. Investor suitability with respect to the trust units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

In the ordinary course of their various business activities, the underwriters and their respective affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers, and such investment and securities activities may involve securities and/or instruments of Enduro Sponsor and the trust. The underwriters and their respective affiliates may also make investment recommendations and/or publish or express independent research views in respect of such securities or instruments and may at any time hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments. Additionally, affiliates of RBC Capital Markets, LLC and Wells Fargo Securities, LLC are lenders under Enduro Sponsor’s senior secured credit agreement and will receive a substantial portion of the proceeds from this offering pursuant to the repayment of borrowings thereunder.

105

LEGAL MATTERS

Richards, Layton & Finger, P.A., as special Delaware counsel to the trust, will give a legal opinion as to the validity of the trust units. Latham & Watkins LLP, Houston, Texas, will give opinions as to certain other matters relating to the offering, including the tax opinion described in the section of this prospectus captioned “Federal Income Tax Consequences.” Certain legal matters in connection with the trust units offered hereby will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas. Baker Botts L.L.P. performs legal services for Enduro Sponsor and its affiliates from time to time on matters unrelated to this offering.

EXPERTS

Certain information appearing in this registration statement regarding the December 31, 2010 estimated quantities of reserves of Enduro Sponsor, the Underlying Properties and the Net Profits Interest owned by the trust, the future net revenues from those reserves and their present value is based on estimates of the reserves and present values prepared by or derived from estimates prepared by Cawley, Gillespie & Associates, Inc., independent petroleum engineers.

The audited financial statements included in this prospectus and registration statement as listed on the index to financial statements on page F-1 and the index to financial statements of Enduro Sponsor on page ENDURO F-1 have been audited by Ernst & Young, LLP, independent registered public accounting firm, as set forth in their reports thereon appearing elsewhere herein, and are included in reliance upon such reports given upon the authority of such firm as experts in accounting and auditing.

WHERE YOU CAN FIND MORE INFORMATION

The trust and Enduro Sponsor have filed with the SEC in Washington, D.C. a registration statement, including all amendments, under the Securities Act relating to the trust units. As permitted by the rules and regulations of the SEC, this prospectus does not contain all of the information contained in the registration statement and the exhibits and schedules to the registration statement. You may read and copy the registration statement at the SEC’s public reference room at 100 F Street, N.E., Washington, D.C. 20549. You may request copies of these documents, upon payment of a duplicating fee, by writing to the SEC at the address in the previous sentence. To obtain information on the operation of the public reference room you may call the SEC at (800) SEC-0330. The SEC maintains a web site on the Internet at http://www.sec.gov. The trust’s and Enduro Sponsor’s registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC’s web site.

The trustee intends to furnish the trust unitholders with annual reports containing the trust’s audited consolidated financial statements and to furnish or make available to the trust unitholders quarterly reports containing the trust’s unaudited interim financial information for the first three fiscal quarters of each of the trust’s fiscal years.

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GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS

In this prospectus the following terms have the meanings specified below.

Bbl — One stock tank barrel of 42 U.S. gallons liquid volume, used herein in reference to crude oil and other liquid hydrocarbons.

Boe — One stock tank barrel of oil equivalent, computed on an approximate energy equivalent basis that one Bbl of crude oil equals six Mcf of natural gas.

Btu — A British Thermal Unit, a common unit of energy measurement.

Completion — The installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Development Well — A well drilled into a proved oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Differential — The difference between a benchmark price of oil and natural gas, such as the NYMEX crude oil spot, and the wellhead price received.

Estimated future net revenues — Also referred to as “estimated future net cash flows.” The result of applying current prices of oil and natural gas to estimated future production from oil and natural gas proved reserves, reduced by estimated future expenditures, based on current costs to be incurred, in developing and producing the proved reserves, excluding overhead.

Farm-in or farm-out agreement — An agreement under which the owner of a working interest in an oil or natural gas lease typically assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farm-in” while the interest transferred by the assignor is a “farm-out.”

Field — An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Gross acres or gross wells — The total acres or wells, as the case may be, in which a working interest is owned.

Horizontal well — A well that starts off being drilled vertically but which is eventually curved to become horizontal (or near horizontal) in order to parallel a particular geologic formation.

MBbl — One thousand barrels of crude oil or condensate.

MBoe — One thousand barrels of oil equivalent.

Mcf — One thousand cubic feet of natural gas.

MMBoe — One million barrels of oil equivalent.

MMBtu — One million British Thermal Units.

MMcf — One million cubic feet of natural gas.

Net acres or net wells — The sum of the fractional working interests owned in gross acres or wells, as the case may be.

Net profits interest — A nonoperating interest that creates a share in gross production from an operating or working interest in oil and natural gas properties. The share is measured by net profits from the sale of production after deducting costs associated with that production.

107

Net revenue interest — An interest in all oil and natural gas produced and saved from, or attributable to, a particular property, net of all royalties, overriding royalties, net profits interests, carried interests, reversionary interests and any other burdens to which the person’s interest is subject.

Plugging and abandonment — Activities to remove production equipment and seal off a well at the end of a well’s economic life.

Proved developed reserves — Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved reserves — Under SEC rules for fiscal years ending on or after December 31, 2009, proved reserves are defined as:

Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, LKH, as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil, HKO, elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Under SEC rules for fiscal years ending prior to December 31, 2009, proved reserves are defined as:

The estimated quantities of crude oil and natural gas, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural

108

occurrence of hydrocarbons controls the lower proved limit of the reservoir. Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the proved classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based. Estimates of proved reserves do not include the following: (A) Oil that may become available from known reservoirs but is classified separately as indicated additional reserves; (B) crude oil and natural gas, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil and natural gas, that may occur in undrilled prospects; and (D) crude oil and natural gas, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved undeveloped reserves — Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

PV-10 — The present value of estimated future net revenues using a discount rate of 10% per annum.

Recompletion — The completion for production of an existing well bore in another formation from which that well has been previously completed.

Reservoir — A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Working interest — The right granted to the lessee of a property to explore for and to produce and own oil, gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

Workover — Operations on a producing well to restore or increase production.

109

INDEX TO FINANCIAL STATEMENTS


PREDECESSOR UNDERLYING PROPERTIES:
Unaudited Statements of Revenues and Direct Operating Expenses for the Three Months Ended March 31, 2011 and 2010			F-2
Notes to Unaudited Statements of Revenues and Direct Operating Expenses			F-3
Report of Independent Registered Public Accounting Firm			F-4
Statements of Revenues and Direct Operating Expenses for Each of the Three Years in the Period Ended December 31, 2010			F-5
Notes to Statements of Revenues and Direct Operating Expenses			F-6
SAMSON PERMIAN BASIN ASSETS:
Unaudited Statements of Revenues and Direct Operating Expenses for the Three Months Ended March 31, 2011 and 2010			F-11
Notes to Unaudited Statements of Revenues and Direct Operating Expenses			F-12
Report of Independent Registered Public Accounting Firm			F-13
Statements of Revenues and Direct Operating Expenses for Each of the Three Years in the Period Ended December 31, 2010			F-14
Notes to Statements of Revenues and Direct Operating Expenses			F-15
CONOCOPHILLIPS PERMIAN BASIN ASSETS:
Unaudited Statements of Revenues and Direct Operating Expenses for the Three Months Ended March 31, 2011 and 2010			F-19
Notes to Unaudited Statements of Revenues and Direct Operating Expenses			F-20
Report of Independent Registered Public Accounting Firm			F-21
Statements of Revenues and Direct Operating Expenses for Each of the Three Years in the Period Ended December 31, 2010			F-22
Notes to Statements of Revenues and Direct Operating Expenses			F-23
UNAUDITED PRO FORMA COMBINED UNDERLYING PROPERTIES:
Introduction			F-27
Unaudited Pro Forma Combined Statements of Revenues and Direct Operating Expenses for the Three Months Ended March 31, 2011 and for the Years Ended December 31, 2010 and 2009			F-28
ENDURO ROYALTY TRUST:
Report of Independent Registered Public Accounting Firm			F-31
Statement of Assets and Trust Corpus as of May 12, 2011			F-32
Notes to Statement of Assets and Trust Corpus			F-33
Unaudited Pro Forma Financial Statements:
Introduction			F-35
Unaudited Pro Forma Statement of Assets and Trust Corpus as of May 12, 2011			F-36
Unaudited Pro Forma Statements of Distributable Income for the Three Months Ended March 31, 2011 and for the Year Ended December 31, 2010			F-37
Notes to Unaudited Pro Forma Financial Statements			F-38

The audited financial statements of the Predecessor can be found beginning on
page ENDURO F-1.

F-1

PREDECESSOR UNDERLYING PROPERTIES

UNAUDITED STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES


	Three Months Ended March 31,
	2011		2010
	(In thousands)

Revenues:
Oil	$	335	$	433
Natural gas		4,477		6,632

Total revenues		4,812		7,065

Direct operating expenses:
Lease operating		1,238		1,118
Gathering and processing		386		307
Production and other taxes		243		426

Total direct operating expenses		1,867		1,851

Excess of revenues over direct operating expenses	$	2,945	$	5,214

The accompanying notes are an integral part of these statements.

F-2

PREDECESSOR UNDERLYING PROPERTIES

NOTES TO UNAUDITED STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES


1.	Basis of Presentation

On December 1, 2010 (the “Acquisition Date”), Enduro Resource Partners LLC (“Enduro”) completed the acquisition of certain oil and natural gas properties located in East Texas and North Louisiana from Denbury Resources Inc. (“Denbury”) for a cash purchase price of approximately $217.4 million. These assets were acquired by Denbury on March 9, 2010 in connection with Denbury’s acquisition of Encore Acquisition Company (“Encore”). The portion of these properties Enduro expects to contribute to Enduro Royalty Trust are collectively referred to herein as the “Predecessor Underlying Properties.”

The accompanying unaudited statements of revenues and direct operating expenses are presented on the accrual basis of accounting and were derived from the historical accounting records of Enduro for periods subsequent to the Acquisition Date and of Denbury and Encore for their respective ownership periods prior to the Acquisition Date.

During the periods presented, the Predecessor Underlying Properties were not accounted for as a separate division and therefore certain costs such as depletion, depreciation, and amortization, accretion of asset retirement obligations, general and administrative expenses, interest, income taxes, and other expenses of an indirect nature were not allocated to the individual properties. Any attempt to allocate such indirect expenses would require significant and judgmental allocations, which would be arbitrary and would not be indicative of the performance of the properties had they been owned by Enduro. As a result of the exclusion of these various expenses, the accompanying unaudited statements of revenues and direct operating expenses are not indicative of the financial condition or results of operations of the Predecessor Underlying Properties and such amounts may not be representative of future operations.

These unaudited statements of revenues and direct operating expenses do not represent a complete set of financial statements reflecting the financial position, results of operations, shareholders’ equity, and cash flows of the Predecessor Underlying Properties. In the opinion of management, the accompanying unaudited statements of revenues and direct operating expenses include all adjustments considered necessary for fair presentation on the basis described above. All adjustments are of a normal recurring nature.


2.	Contingencies

The activities of the Predecessor Underlying Properties are subject to potential claims and litigation in the normal course of operations. Enduro’s management does not believe that any liability resulting from any pending or threatened litigation will have a material adverse effect on the operations or financial results of the Predecessor Underlying Properties.


3.	Cash Flow Information

Capital expenditures relating to the Predecessor Underlying Properties were approximately $6.1 million and $1.5 million for the three months ended March 31, 2011 and 2010, respectively. Other cash flow information is not available on a stand-alone basis for the Predecessor Underlying Properties.


4.	Subsequent Events

Subsequent events have been evaluated through July 1, 2011, the date the statements were available to be issued, to ensure that any subsequent events that met the criteria for recognition or disclosure in this report have been included. No subsequent events requiring recognition or disclosure have occurred.

F-3

Report of Independent Registered Public Accounting Firm

To the Board of Managers and Members of Enduro Resource Partners LLC:

We have audited the accompanying statements of revenues and direct operating expenses of the Predecessor Underlying Properties, described in Note 1, for the years ended December 31, 2010, 2009 and 2008. These statements are the responsibility of Enduro Resource Partners LLC’s management. Our responsibility is to express an opinion on these statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the statements are free of material misstatement. We were not engaged to perform an audit of the internal controls over financial reporting of the revenues and direct operating expenses of the Predecessor Underlying Properties. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate for the circumstances, but not for the purpose of expressing an opinion on the effectiveness of internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the statements. We believe that our audits provide a reasonable basis for our opinion.

The accompanying statements reflect the revenues and direct operating expenses of the Predecessor Underlying Properties, as described in Note 1, and are not intended to be a complete presentation of the Predecessor Underlying Properties’ revenues and expenses.

In our opinion, the statements referred to above present fairly, in all material respects, the revenues and direct operating expenses of the Predecessor Underlying Properties for the years ended December 31, 2010, 2009 and 2008 in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Fort Worth, Texas

May 11, 2011

F-4

PREDECESSOR UNDERLYING PROPERTIES

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES


	Year Ended December 31,
	2010		2009		2008
	(In thousands)

Revenues:
Oil	$	1,345	$	1,685	$	3,057
Natural gas		21,112		22,519		54,485

Total revenues		22,457		24,204		57,542

Direct operating expenses:
Lease operating		4,484		5,365		4,695
Gathering and processing		1,522		1,474		2,471
Production and other taxes		1,373		1,965		2,259

Total direct operating expenses		7,379		8,804		9,425

Excess of revenues over direct operating expenses	$	15,078	$	15,400	$	48,117

The accompanying notes are an integral part of these statements.

F-5

PREDECESSOR UNDERLYING PROPERTIES

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES


1.	Basis of Presentation

On December 1, 2010 (the “Acquisition Date”), Enduro Resource Partners LLC (“Enduro”) completed the acquisition of certain oil and natural gas properties located in East Texas and North Louisiana from Denbury Resources Inc. (“Denbury”) for a cash purchase price of approximately $213.8 million, subject to post-closing adjustments. These assets were acquired by Denbury on March 9, 2010 in connection with Denbury’s acquisition of Encore Acquisition Company (“Encore”). The portion of these properties Enduro expects to contribute to Enduro Royalty Trust are collectively referred to herein as the “Predecessor Underlying Properties.”

The accompanying statements of revenues and direct operating expenses are presented on the accrual basis of accounting and were derived from the historical accounting records of Enduro for periods subsequent to the Acquisition Date and of Denbury and Encore for their respective ownership periods prior to the Acquisition Date.

During the periods presented, the Predecessor Underlying Properties were not accounted for as a separate division and therefore certain costs such as depletion, depreciation, and amortization, accretion of asset retirement obligations, general and administrative expenses, interest, income taxes, and other expenses of an indirect nature were not allocated to the individual properties. Any attempt to allocate such indirect expenses would require significant and judgmental allocations, which would be arbitrary and would not be indicative of the performance of the properties had they been owned by Enduro. As a result of the exclusion of these various expenses, the accompanying statements of revenues and direct operating expenses are not indicative of the financial condition or results of operations of the Predecessor Underlying Properties and such amounts may not be representative of future operations.

Full separate financial statements prepared in accordance with generally accepted accounting principles are not presented as the information necessary to prepare such statements is neither readily available on an individual property basis nor practicable to obtain in these circumstances. Accordingly, the statements of revenues and direct operating expenses of the Predecessor Underlying Properties are presented in lieu of the financial statements otherwise required under Rules 3-01 and 3-02 of Regulation S-X by the Securities and Exchange Commission (“SEC”).


2.	Significant Accounting Policies


*(a)*	*Use of Estimates*

Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the statements of revenues and direct operating expenses. Actual balances and results could be different from those estimates.


*(b)*	*Revenue Recognition*

Oil and natural gas revenues are recognized when such products have been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibilities of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. Revenues are reported net of royalties and other amounts due to third parties.


*(c)*	*Direct Operating Expenses*

Direct operating expenses are recognized when incurred and consist of the direct expenses of operating the Predecessor Underlying Properties. Direct operating expenses include lease operating,

F-6

PREDECESSOR UNDERLYING PROPERTIES

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES — (Continued)

gathering, processing, and production and other tax expenses. Lease operating expenses include the costs of maintaining and operating property and equipment on producing oil and natural gas leases and include field labor, insurance, maintenance, repairs, utilities and supplies, and well workover and field expenses. Gathering and processing expenses include the costs of oil and/or natural gas taken in-kind for the use of gas processing facilities as well as maintenance, repair, and other operating costs incurred in gathering the production. Production and other taxes consist of severance and ad valorem taxes. Production taxes are recorded at the time transfer of title occurs. Such taxes represent a fixed percentage of production and are calculated and paid to the state governments in accordance with applicable regulations.


3.	Contingencies

The activities of the Predecessor Underlying Properties are subject to potential claims and litigation in the normal course of operations. Enduro’s management does not believe that any liability resulting from any pending or threatened litigation will have a materially adverse effect on the operations or financial results of the Predecessor Underlying Properties.


4.	Cash Flow Information

Capital expenditures relating to the Predecessor Underlying Properties were approximately $7.8 million, $16.9 million, and $53.7 million for the years ended December 31, 2010, 2009, and 2008, respectively. Other cash flow information is not available on a stand-alone basis for the Predecessor Underlying Properties.


5.	Subsequent Events

Subsequent events have been evaluated through May 11, 2011, the date the statements were available to be issued, to ensure that any subsequent events that met the criteria for recognition or disclosure in this report have been included. No subsequent events requiring recognition or disclosure have occurred.


6.	Supplemental Oil and Natural Gas Disclosures (Unaudited)

The following unaudited supplemental oil and natural gas disclosures were derived from reserve reports which were prepared by Enduro’s, Denbury’s and Encore’s reserve engineers and are presented in accordance with the Financial Accounting Standards Board ASC Topic 932, Extractive Activities — Oil and Gas (“ASC 932”). The unaudited supplemental information reflects the revised oil and natural gas reserve estimation and disclosure requirements of the SEC Modernization of Oil and Gas Reporting rules, which were issued by the SEC in 2008 and were effective December 31, 2009. The following unaudited supplemental information for 2010 and 2009 has been presented in accordance with the revised reserve estimation and disclosure rules, which were not applied retrospectively. Accordingly, the information for 2008 is presented in accordance with the oil and gas disclosure requirements effective during that period.

Oil and Natural Gas Reserve Quantities

Proved reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing, and production may cause either upward or downward revisions of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating

F-7

PREDECESSOR UNDERLYING PROPERTIES

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES — (Continued)

costs. The process of estimating quantities of oil and gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reserve. Consequently, material revisions to existing reserve estimates may occur from time to time.

The following table presents the estimated remaining net proved and proved developed oil and natural gas reserves of the Predecessor Underlying Properties and changes therein, for the periods indicated.


	Oil			Natural Gas			Total
	(MBbls)			(MMcf)			(MBOE)

January 1, 2008		114			38,126			6,468
Revisions of previous estimates		70			26,511			4,489
Production		(33	)		(6,449	)		(1,108	)

December 31, 2008		151			58,188			9,849
Revisions of previous estimates		(16	)		2,490			399
Production		(31	)		(6,069	)		(1,043	)

December 31, 2009		104			54,609			9,205
Revisions of previous estimates		(61	)		14,673			2,385
Production		(18	)		(4,976	)		(847	)

December 31, 2010		25			64,306			10,743

Proved developed reserves as of:
December 31, 2008		106			43,480			7,353
December 31, 2009		59			35,497			5,975
December 31, 2010		25			31,105			5,209
Proved undeveloped reserves as of:
December 31, 2008		45			14,708			2,496
December 31, 2009		45			19,112			3,230
December 31, 2010		—			33,201			5,534

Standardized Measure of Discounted Future Net Cash Flows

Estimated discounted future net cash flows and changes therein were determined for the Predecessor Underlying Properties in accordance with ASC 932. Future cash inflows for 2010 and 2009 were computed by applying the average prices of oil and natural gas during the 12-month period to the period-end quantities of those proved reserves (with consideration of price changes only to the extent provided by contractual arrangements). The average prices were determined using the arithmetic average of the prices in effect on the first day of the month for each month within the period. This same 12-month average price was also used in calculating the aggregate amount of (and changes in) future cash inflows related to the standardized measure of discounted future net cash flows. Future cash inflows for 2008 were computed by using the year-end oil and natural gas prices in accordance with the disclosure requirements effective during that period.

F-8

PREDECESSOR UNDERLYING PROPERTIES

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES — (Continued)

The prices per unit used for the Predecessor Underlying Properties’ proved reserves and future net revenues are as follows:


	December 31,
	2010		2009		2008

Oil (per Bbl)	$	79.43	$	61.18	$	44.60
Natural gas (per Mcf)	$	4.37	$	3.83	$	5.62

Future development and production costs were computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves based on period-end costs assuming continuation of existing economic conditions. No future income tax expense was computed as taxable income arising from the operations of the properties accrues to the owner. An annual discount rate of 10% was used to reflect the timing of the future net cash flows.

Discounted future cash flow estimates like those shown below are not intended to present, nor should they be interpreted to present, the fair value of the Predecessor Underlying Properties’ oil and natural gas properties. Estimates of fair value should also consider probable and possible reserves, anticipated future commodity prices, interest rates, changes in development and production costs, and risks associated with future production. Because of these and other considerations, any estimate of fair value is necessarily subjective and imprecise.

The following table presents the estimates of the standardized measure of discounted future net cash flows from proved reserves of oil and natural gas for the periods indicated.


	Year Ended December 31,
	2010			2009			2008
	(In thousands)

Future cash inflows	$	263,643		$	200,931		$	311,799
Future production costs		(62,667	)		(75,873	)		(94,767	)
Future development costs		(51,674	)		(37,531	)		(39,163	)

Future net cash flows		149,302			87,527			177,869
10% discount for estimating timing of cash flows		(79,745	)		(41,852	)		(81,788	)

Standardized measure of discounted future net cash flows	$	69,557		$	45,675		$	96,081

F-9

PREDECESSOR UNDERLYING PROPERTIES

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES — (Continued)

The following table presents the changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the periods indicated.


	Year Ended December 31,
	2010			2009			2008
				(In thousands)

Sales of oil and natural gas produced, net of production costs	$	(15,078	)	$	(15,400	)	$	(48,117	)
Net changes in prices and production costs		24,282			(44,320	)		(27,554	)
Revisions of previous quantity estimates		23,286			2,930			53,925
Development costs incurred during the period		7,779			16,926			26,841
Accretion of discount		4,567			9,608			9,827
Change in estimated future development costs		(17,147	)		(11,963	)		(30,633	)
Timing and other		(3,807	)		(8,187	)		13,527

Net change in standardized measure		23,882			(50,406	)		(2,184	)
Standardized measure, beginning of year		45,675			96,081			98,265

Standardized measure, end of year	$	69,557		$	45,675		$	96,081

F-10

SAMSON PERMIAN BASIN ASSETS

UNAUDITED STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES


	Three Months Ended March 31,
	2011		2010
	(In thousands)

Revenues:
Oil	$	4,351	$	4,289
Natural gas		1,213		1,680

Total revenues		5,564		5,969

Direct operating expenses:
Lease operating		785		919
Gathering and processing		56		56
Production and other taxes		377		441

Total direct operating expenses		1,218		1,416

Excess of revenues over direct operating expenses	$	4,346	$	4,553

The accompanying notes are an integral part of these statements.

F-11

SAMSON PERMIAN BASIN ASSETS

NOTES TO UNAUDITED STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES


1.	Basis of Presentation

On January 5, 2011 (the “Acquisition Date”), Enduro Resource Partners LLC (“Enduro”) completed the acquisition of certain oil and natural gas properties located in the Permian Basin in Texas and New Mexico (the “Samson Permian Basin Assets”) from Samson Investment Company and related subsidiaries (collectively, “Samson”) for a cash purchase price of approximately $133.8 million, subject to post-closing adjustments.

During the periods presented, the Samson Permian Basin Assets were not accounted for as a separate division and therefore certain costs such as depletion, depreciation, and amortization, accretion of asset retirement obligations, general and administrative expenses, interest, income taxes, and other expenses of an indirect nature were not allocated to the individual properties. Any attempt to allocate such indirect expenses would require significant and judgmental allocations, which would be arbitrary and would not be indicative of the performance of the properties had they been owned by Enduro. As a result of the exclusion of these various expenses, the accompanying unaudited statements of revenues and direct operating expenses are not indicative of the financial condition or results of operations of the Samson Permian Basin Assets and such amounts may not be representative of future operations.

These unaudited statements of revenues and direct operating expenses do not represent a complete set of financial statements reflecting the financial position, results of operations, shareholders’ equity, and cash flows of the Samson Permian Basin Assets. In the opinion of management, the accompanying unaudited statements of revenues and direct operating expenses include all adjustments considered necessary for fair presentation on the basis described above. All adjustments are of a normal recurring nature.


2.	Contingencies

The activities of the Samson Permian Basin Assets are subject to potential claims and litigation in the normal course of operations. Enduro’s management does not believe that any liability resulting from any pending or threatened litigation will have a materially adverse effect on the operations or financial results of the Samson Permian Basin Assets.


3.	Cash Flow Information

Capital expenditures relating to the Samson Permian Basin Assets were approximately $5,000 and $92,000 for the three months ended March 31, 2011 and 2010, respectively. Other cash flow information is not available on a stand-alone basis for the Samson Permian Basin Assets.


4.	Subsequent Events

F-12

Report of Independent Registered Public Accounting Firm

To the Board of Managers and Members of Enduro Resource Partners LLC:

We have audited the accompanying statements of revenues and direct operating expenses of the Samson Permian Basin Assets, described in Note 1, for the years ended December 31, 2010, 2009 and 2008. These statements are the responsibility of Enduro Resource Partners LLC’s management. Our responsibility is to express an opinion on these statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the statements are free of material misstatement. We were not engaged to perform an audit of the internal controls over financial reporting of the revenues and direct operating expenses of the Samson Permian Basin Assets. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate for the circumstances, but not for the purpose of expressing an opinion on the effectiveness of internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the statements. We believe that our audits provide a reasonable basis for our opinion.

The accompanying statements reflect the revenues and direct operating expenses of the Samson Permian Basin Assets, as described in Note 1, and are not intended to be a complete presentation of the Samson Permian Basin Assets’ revenues and expenses.

In our opinion, the statements referred to above present fairly, in all material respects, the revenues and direct operating expenses of the Samson Permian Basin Assets for the years ended December 31, 2010, 2009 and 2008 in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Tulsa, Oklahoma

May 9, 2011

F-13

SAMSON PERMIAN BASIN ASSETS

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES


	Year Ended December 31,
	2010		2009		2008
	(In thousands)

Revenues:
Oil	$	16,626	$	13,174	$	23,730
Natural gas		5,650		4,733		9,770

Total revenues		22,276		17,907		33,500

Direct operating expenses:
Lease operating		3,438		3,783		4,327
Gathering and processing		212		177		178
Production and other taxes		1,702		1,558		2,549

Total direct operating expenses		5,352		5,518		7,054

Excess of revenues over direct operating expenses	$	16,924	$	12,389	$	26,446

The accompanying notes are an integral part of these statements.

F-14

SAMSON PERMIAN BASIN ASSETS

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES


1.	Basis of Presentation

During the periods presented, the Samson Permian Basin Assets were not accounted for as a separate division and therefore certain costs such as depletion, depreciation, and amortization, accretion of asset retirement obligations, general and administrative expenses, interest, income taxes, and other expenses of an indirect nature were not allocated to the individual properties. Any attempt to allocate such indirect expenses would require significant and judgmental allocations, which would be arbitrary and would not be indicative of the performance of the properties had they been owned by Enduro. As a result of the exclusion of these various expenses, the accompanying statements of revenues and direct operating expenses are not indicative of the financial condition or results of operations of the Samson Permian Basin Assets and such amounts may not be representative of future operations.

Full separate financial statements prepared in accordance with generally accepted accounting principles are not presented as the information necessary to prepare such statements is neither readily available on an individual property basis nor practicable to obtain in these circumstances. Accordingly, the statements of revenues and direct operating expenses of the Samson Permian Basin Assets are presented in lieu of the financial statements otherwise required under Rules 3-01 and 3-02 of Regulation S-X by the Securities and Exchange Commission (“SEC”).


2.	Significant Accounting Policies


*(a)*	*Use of Estimates*


*(b)*	*Revenue Recognition*


*(c)*	*Direct Operating Expenses*

Direct operating expenses are recognized when incurred and consist of the direct expenses of operating the Samson Permian Basin Assets. Direct operating expenses include lease operating, gathering, processing, and production and other tax expenses. Lease operating expenses include the costs of maintaining and operating property and equipment on producing oil and natural gas leases and include field labor, insurance, maintenance, repairs, utilities and supplies, and well workover and

F-15

SAMSON PERMIAN BASIN ASSETS

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES — (Continued)

field expenses. Gathering and processing expenses include the costs of oil and/or natural gas taken in-kind for the use of gas processing facilities as well as maintenance, repair, and other operating costs incurred in gathering the production. Production and other taxes consist of severance and ad valorem taxes. Production taxes are recorded at the time transfer of title occurs. Such taxes represent a fixed percentage of production and are calculated and paid to the state governments in accordance with applicable regulations.


3.	Contingencies


4.	Cash Flow Information (Unaudited)

Capital expenditures relating to the Samson Permian Basin Assets were approximately $799,000, $968,000, and $5,628,000 for the years ended December 31, 2010, 2009, and 2008, respectively. Other cash flow information is not available on a stand-alone basis for the Samson Permian Basin Assets.


5.	Subsequent Events

Subsequent events have been evaluated through May 9, 2011, the date the statements were available to be issued, to ensure that any subsequent events that met the criteria for recognition or disclosure in this report have been included. No subsequent events requiring recognition or disclosure have occurred.


6.	Supplemental Oil and Natural Gas Disclosures (Unaudited)

The following unaudited supplemental oil and natural gas disclosures were derived from reserve reports which were prepared by Enduro’s reserve engineers and are presented in accordance with the Financial Accounting Standards Board ASC Topic 932, Extractive Activities — Oil and Gas (“ASC 932”). The unaudited supplemental information reflects the revised oil and natural gas reserve estimation and disclosure requirements of the SEC Modernization of Oil and Gas Reporting rules, which were issued by the SEC in 2008 and were effective December 31, 2009. The following unaudited supplemental information for 2010 and 2009 has been presented in accordance with the revised reserve estimation and disclosure rules, which were not applied retrospectively. Accordingly, the information for 2008 is presented in accordance with the oil and gas disclosure requirements effective during that period.

Oil and Natural Gas Reserve Quantities

F-16

SAMSON PERMIAN BASIN ASSETS

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES — (Continued)

each reserve. Consequently, material revisions to existing reserve estimates may occur from time to time.

The following table presents the estimated remaining net proved and proved developed oil and natural gas reserves of the Samson Permian Basin Assets and changes therein, for the periods indicated.


	Oil			Natural Gas			Total
	(MBbls)			(MMcf)			(MBOE)

January 1, 2008		3,835			14,399			6,235
Revisions of previous estimates		(351	)		(517	)		(437	)
Production		(246	)		(1,164	)		(440	)

December 31, 2008		3,238			12,718			5,358
Revisions of previous estimates		139			(150	)		114
Production		(233	)		(1,110	)		(418	)

December 31, 2009		3,144			11,458			5,054
Revisions of previous estimates		120			379			183
Production		(216	)		(1,056	)		(392	)

December 31, 2010		3,048			10,781			4,845

Proved developed reserves as of:
December 31, 2008		3,238			12,718			5,358
December 31, 2009		3,144			11,458			5,054
December 31, 2010		3,048			10,781			4,845

Standardized Measure of Discounted Future Net Cash Flows

Estimated discounted future net cash flows and changes therein were determined for the Samson Permian Basin Assets in accordance with ASC 932. Future cash inflows for 2010 and 2009 were computed by applying the average prices of oil and natural gas during the 12-month period to the period-end quantities of those proved reserves (with consideration of price changes only to the extent provided by contractual arrangements). The average prices were determined using the arithmetic average of the prices in effect on the first day of the month for each month within the period. This same 12-month average price was also used in calculating the aggregate amount of (and changes in) future cash inflows related to the standardized measure of discounted future net cash flows. Future cash inflows for 2008 were computed by using the year-end oil and natural gas prices in accordance with the disclosure requirements effective during that period.

The prices per unit used for the Samson Permian Basin Assets’ proved reserves and future net revenues are as follows:


	December 31,
	2010		2009		2008

Oil (per Bbl)	$	79.43	$	61.18	$	44.60
Natural gas (per Mcf)	$	4.37	$	3.83	$	5.62

F-17

SAMSON PERMIAN BASIN ASSETS

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES — (Continued)

computed as taxable income arising from the operations of the properties accrues to the owner. An annual discount rate of 10% was used to reflect the timing of the future net cash flows.

Discounted future cash flow estimates like those shown below are not intended to present, nor should they be interpreted to present, the fair value of the Samson Permian Basin Assets’ oil and natural gas properties. Estimates of fair value should also consider probable and possible reserves, anticipated future commodity prices, interest rates, changes in development and production costs, and risks associated with future production. Because of these and other considerations, any estimate of fair value is necessarily subjective and imprecise.

The following table presents the estimates of the standardized measure of discounted future net cash flows from proved reserves of oil and natural gas for the periods indicated.


	Year Ended December 31,
	2010			2009			2008
	(In thousands)

Future cash inflows	$	292,253		$	239,673		$	224,628
Future production costs		(107,372	)		(96,804	)		(92,314	)

Future net cash flows		184,881			142,869			132,314
10% discount for estimating timing of cash flows		(99,927	)		(73,986	)		(64,551	)

Standardized measure of discounted future net cash flows	$	84,954		$	68,883		$	67,763

The following table presents the changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the periods indicated.


	Year Ended December 31,
	2010			2009			2008
	(In thousands)

Sales of oil and natural gas produced, net of production costs	$	(16,924	)	$	(12,389	)	$	(26,446	)
Net changes in prices and production costs		25,022			10,094			(83,425	)
Revisions of previous quantity estimates		3,361			1,650			(4,972	)
Accretion of discount		6,888			6,776			16,207
Timing and other		(2,276	)		(5,011	)		4,330

Net change in standardized measure		16,071			1,120			(94,306	)
Standardized measure, beginning of year		68,883			67,763			162,069

Standardized measure, end of year	$	84,954		$	68,883		$	67,763

F-18

CONOCOPHILLIPS PERMIAN BASIN ASSETS

UNAUDITED STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES


	Three Months Ended March 31,
	2011		2010
	(In thousands)

Revenues:
Oil	$	15,464	$	12,632
Natural gas		1,572		1,526

Total revenues		17,036		14,158

Direct operating expenses:
Lease operating		4,162		4,169
Gathering and processing		47		56
Production and other taxes		1,385		1,185

Total direct operating expenses		5,594		5,410

Excess of revenues over direct operating expenses	$	11,442	$	8,748

The accompanying notes are an integral part of these statements.

F-19

CONOCOPHILLIPS PERMIAN BASIN ASSETS

NOTES TO UNAUDITED STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES


1.	Basis of Presentation

On February 28, 2011 (the “Acquisition Date”), Enduro Resource Partners LLC (“Enduro”) completed the acquisition of certain oil and natural gas properties located in the Permian Basin in Texas and New Mexico (the “ConocoPhillips Permian Basin Assets”) from ConocoPhillips Company and a related subsidiary (collectively, “ConocoPhillips”) for a cash purchase price of approximately $314.2 million, subject to post-closing adjustments.

The accompanying unaudited statements of revenues and direct operating expenses are presented on the accrual basis of accounting and were derived from the historical accounting records of Enduro for periods subsequent to the Acquisition Date and of ConocoPhillips for periods prior to the Acquisition Date.

During the periods presented, the ConocoPhillips Permian Basin Assets were not accounted for as a separate division and therefore certain costs such as depletion, depreciation, and amortization, accretion of asset retirement obligations, general and administrative expenses, interest, income taxes, and other expenses of an indirect nature were not allocated to the individual properties. Any attempt to allocate such indirect expenses would require significant and judgmental allocations, which would be arbitrary and would not be indicative of the performance of the properties had they been owned by Enduro. As a result of the exclusion of these various expenses, the accompanying unaudited statements of revenues and direct operating expenses are not indicative of the financial condition or results of operations of the ConocoPhillips Permian Basin Assets and such amounts may not be representative of future operations.

These unaudited statements of revenues and direct operating expenses do not represent a complete set of financial statements reflecting the financial position, results of operations, shareholders’ equity, and cash flows of the ConocoPhillips Permian Basin Assets. In the opinion of management, the accompanying unaudited statements of revenues and direct operating expenses include all adjustments considered necessary for fair presentation on the basis described above. All adjustments are of a normal recurring nature.


2.	Contingencies

The activities of the ConocoPhillips Permian Basin Assets are subject to potential claims and litigation in the normal course of operations. Enduro’s management does not believe that any liability resulting from any pending or threatened litigation will have a material adverse effect on the operations or financial results of the ConocoPhillips Permian Basin Assets.


3.	Cash Flow Information

Capital expenditures relating to the ConocoPhillips Permian Basin Assets were approximately $6.0 million and $0.2 million for the three months ended March 31, 2011 and 2010, respectively. Other cash flow information is not available on a stand-alone basis for the ConocoPhillips Permian Basin Assets.


4.	Subsequent Events

F-20

Report of Independent Registered Public Accounting Firm

To the Board of Managers and Members of Enduro Resource Partners LLC:

We have audited the accompanying statements of revenues and direct operating expenses of the ConocoPhillips Permian Basin Assets, described in Note 1, for the years ended December 31, 2010, 2009 and 2008. These statements are the responsibility of Enduro Resource Partners LLC’s management. Our responsibility is to express an opinion on these statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the statements are free of material misstatement. We were not engaged to perform an audit of the internal controls over financial reporting of the revenues and direct operating expenses of the ConocoPhillips Permian Basin Assets. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate for the circumstances, but not for the purpose of expressing an opinion on the effectiveness of internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the statements. We believe that our audits provide a reasonable basis for our opinion.

The accompanying statements reflect the revenues and direct operating expenses of the ConocoPhillips Permian Basin Assets, as described in Note 1, and are not intended to be a complete presentation of the ConocoPhillips Permian Basin Assets’ revenues and expenses.

In our opinion, the statements referred to above present fairly, in all material respects, the revenues and direct operating expenses of the ConocoPhillips Permian Basin Assets for the years ended December 31, 2010, 2009 and 2008 in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Tulsa, Oklahoma

May 9, 2011

F-21

CONOCOPHILLIPS PERMIAN BASIN ASSETS

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES


	Year Ended December 31,
	2010		2009		2008
			(In thousands)

Revenues:
Oil	$	52,062	$	40,450	$	80,014
Natural gas		7,025		5,801		11,746

Total revenues		59,087		46,251		91,760

Direct operating expenses:
Lease operating		16,657		16,674		20,309
Gathering and processing		243		234		386
Production and other taxes		4,994		3,989		6,409

Total direct operating expenses		21,894		20,897		27,104

Excess of revenues over direct operating expenses	$	37,193	$	25,354	$	64,656

The accompanying notes are an integral part of these statements.

F-22

CONOCOPHILLIPS PERMIAN BASIN ASSETS

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

Class of

Percentage of

Name of Beneficial Owner

Securities

Ownership

Enduro Sponsor

Trust Units

Enduro Resource Partners LLC S-1/A